Energy Future Holdings Corp /TX/ - FORM 10-Q

Attached files

file	filename
EX-31.(A) - SECTION 302 CERTIFICATION - CEO - Energy Future Holdings Corp /TX/	dex31a.htm
EX-99.(A) - CONDENSED CONSOLIDATED STATEMENT OF INCOME - Energy Future Holdings Corp /TX/	dex99a.htm
EX-99.(B) - EFH CONSOLIDATED ADJUSTED EBITDA RECONCILIATION - Energy Future Holdings Corp /TX/	dex99b.htm
EX-31.(B) - SECTION 302 CERTIFICATION - CFO - Energy Future Holdings Corp /TX/	dex31b.htm
EX-32.(B) - SECTION 906 CERTIFICATION - CFO - Energy Future Holdings Corp /TX/	dex32b.htm
EX-99.(C) - TCEH CONSOLIDATED ADJUSTED EBITDA RECONCILIATION - Energy Future Holdings Corp /TX/	dex99c.htm
EX-32.(A) - SECTION 906 CERTIFICATION - CEO - Energy Future Holdings Corp /TX/	dex32a.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2009

— OR —

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number 1-12833

Energy Future Holdings Corp.

(Exact name of registrant as specified in its charter)


Texas		75-2669310
(State of incorporation)		(I.R.S. Employer Identification No.)


1601 Bryan Street, Dallas, TX 75201-3411		(214) 812-4600
(Address of principal executive offices)(Zip Code)		(Registrant’s telephone number)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨ No ¨ (The registrant is not currently required to submit such files.)

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ¨ Accelerated filer ¨ Non-Accelerated filer x Smaller reporting company ¨

Indicate by check mark if the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

As of October 29, 2009, there were 1,667,774,579 shares of common stock outstanding, without par value, of Energy Future Holdings Corp. (substantially all of which were owned by Texas Energy Future Holdings Limited Partnership, Energy Future Holdings Corp.’s parent holding company, and none of which is publicly traded).

TABLE OF CONTENTS


		PAGE
GLOSSARY		ii

PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements
	Condensed Statements of Consolidated Income (Loss) – Three and Nine Months Ended September 30, 2009 and 2008	1

	Condensed Statements of Consolidated Comprehensive Income (Loss) – Three and Nine Months Ended September 30, 2009 and 2008	2

	Condensed Statements of Consolidated Cash Flows – Nine Months Ended September 30, 2009 and 2008	3

	Condensed Consolidated Balance Sheets – September 30, 2009 and December 31, 2008	4

	Notes to Condensed Consolidated Financial Statements	5

	Report of Independent Registered Public Accounting Firm	53

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	54

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	94

Item 4.	Controls and Procedures	100

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	100

Item 1A.	Risk Factors	100

Item 5.	Other Information	100

Item 6.	Exhibits	101

SIGNATURE		103

Energy Future Holdings Corp.’s (EFH Corp.) annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports are made available to the public, free of charge, on the EFH Corp. website at http://www.energyfutureholdings.com, as soon as reasonably practicable after they have been filed with or furnished to the Securities and Exchange Commission. The information on EFH Corp.’s website shall not be deemed a part of, or incorporated by reference into, this report on Form 10-Q. Readers should not rely on or assume the accuracy of any representation or warranty in any agreement that EFH Corp. has filed as an exhibit to this Form 10-Q because such representation or warranty may be subject to exceptions and qualifications contained in separate disclosure schedules, may represent the parties’ risk allocation in the particular transaction, may be qualified by materiality standards that differ from what may be viewed as material for securities law purposes or may no longer continue to be true as of any given date.

This Form 10-Q and other Securities and Exchange Commission filings of EFH Corp. and its subsidiaries occasionally make references to EFH Corp. (or “we,” “our,” “us” or “the company”), EFC Holdings, Intermediate Holding, TCEH, TXU Energy, Luminant, Oncor Holdings or Oncor when describing actions, rights or obligations of their respective subsidiaries. These references reflect the fact that the subsidiaries are consolidated with their respective parent companies for financial reporting purposes. However, these references should not be interpreted to imply that the parent company is actually undertaking the action or has the rights or obligations of the relevant subsidiary company or that the subsidiary company is undertaking an action or has the rights or obligations of its parent company or any other affiliate.

GLOSSARY

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.


2008 Form 10-K		EFH Corp.’s Annual Report on Form 10-K for the year ended December 31, 2008 as recast in a Current Report on Form 8-K filed on May 20, 2009 to reflect the adoption of new accounting and disclosure guidance related to noncontrolling interests

Adjusted EBITDA		Adjusted EBITDA means EBITDA adjusted to exclude non-cash items, unusual items and other adjustments allowable under certain of our debt arrangements. See the definition of EBITDA below. Adjusted EBITDA and EBITDA are not recognized terms under GAAP and, thus, are non-GAAP financial measures. We are providing Adjusted EBITDA in this Form 10-Q (see reconciliation in Exhibit 99(b) and 99(c)) solely because of the important role that Adjusted EBITDA plays in respect of the certain covenants contained in our debt arrangements. We do not intend for Adjusted EBITDA (or EBITDA) to be an alternative to net income as a measure of operating performance or an alternative to cash flows from operating activities as a measure of liquidity or an alternative to any other measure of financial performance presented in accordance with GAAP. Additionally, we do not intend for Adjusted EBITDA (or EBITDA) to be used as a measure of free cash flow available for management’s discretionary use, as the measure excludes certain cash requirements such as interest payments, tax payments and other debt service requirements. Because not all companies use identical calculations, our presentation of Adjusted EBITDA (and EBITDA) may not be comparable to similarly titled measures of other companies.

Competitive Electric segment		Refers to the EFH Corp. business segment that consists principally of TCEH.

CREZ		Competitive Renewable Energy Zone

DOE		US Department of Energy

EBITDA		Refers to earnings (net income) before interest expense, income taxes, depreciation and amortization. See the definition of Adjusted EBITDA above.

EFC Holdings		Refers to Energy Future Competitive Holdings Company, a direct subsidiary of EFH Corp. and the direct parent of TCEH.

EFH Corp.		Refers to Energy Future Holdings Corp., a holding company, and/or its subsidiaries, depending on context. Its major subsidiaries include TCEH and Oncor.

EFH Corp. Senior Notes		Refers collectively to EFH Corp.’s 10.875% Senior Notes due November 1, 2017 (EFH Corp. Cash-Pay Notes) and EFH Corp.’s 11.25%/12.00% Senior Toggle Notes due November 1, 2017 (EFH Corp. Toggle Notes).

EFIH Finance		Refers to EFIH Finance Inc, a direct, wholly-owned subsidiary of Intermediate Holding, formed for the sole purpose of serving as co-issuer with Intermediate Holding of certain debt securities.

EPA		US Environmental Protection Agency

EPC		engineering, procurement and construction


ERCOT		Electric Reliability Council of Texas, the independent system operator and the regional coordinator of various electricity systems within Texas

FASB		Financial Accounting Standards Board, the designated organization in the private sector for establishing standards for financial accounting and reporting

FERC		US Federal Energy Regulatory Commission

Fitch		Fitch Ratings, Ltd. (a credit rating agency)

GAAP		generally accepted accounting principles

GWh		gigawatt-hours

Intermediate Holding		Refers to Energy Future Intermediate Holding Company LLC, a direct, wholly-owned subsidiary of EFH Corp. and the direct parent of Oncor Holdings.

IRS		US Internal Revenue Service

kWh		kilowatt-hours

LIBOR		London Interbank Offered Rate. An interest rate at which banks can borrow funds, in marketable size, from other banks in the London interbank market.

Luminant		Refers to subsidiaries of TCEH engaged in competitive market activities consisting of electricity generation, development and construction of new generation facilities, wholesale energy sales and purchases as well as commodity risk management and trading activities, all largely in Texas.

market heat rate		Heat rate is a measure of the efficiency of converting a fuel source to electricity. The market heat rate is based on the price offer of the marginal supplier in Texas (generally natural gas plants) in generating electricity and is calculated by dividing the wholesale market price of electricity by the market price of natural gas.

Merger		The transaction referred to in “Merger Agreement” (defined immediately below) that was completed on October 10, 2007.

Merger Agreement		Agreement and Plan of Merger, dated February 25, 2007, under which Texas Holdings agreed to acquire EFH Corp.

MMBtu		million British thermal units

Moody’s		Moody’s Investors Services, Inc. (a credit rating agency)

MW		megawatts

MWh		megawatt-hours

NRC		US Nuclear Regulatory Commission

Oncor		Refers to Oncor Electric Delivery Company LLC, a direct, majority-owned subsidiary of Oncor Holdings and an indirect subsidiary of EFH Corp., and/or its consolidated bankruptcy-remote financing subsidiary, Oncor Electric Delivery Transition Bond Company LLC, depending on context, that is engaged in regulated electricity transmission and distribution activities.

iii


Oncor Holdings		Refers to Oncor Electric Delivery Holdings Company LLC, a direct wholly-owned subsidiary of Intermediate Holding and the direct majority owner of Oncor, that is consolidated as a variable interest entity under consolidations accounting standards.

Oncor Ring-Fenced Entities		Refers to Oncor Holdings and its direct and indirect subsidiaries, including Oncor.

OPEB		other postretirement employee benefits

PUCT		Public Utility Commission of Texas

PURA		Texas Public Utility Regulatory Act

Purchase accounting		The purchase method of accounting for a business combination as prescribed by GAAP, whereby the cost or “purchase price” of a business combination, including the amount paid for the equity and direct transaction costs are allocated to identifiable assets and liabilities (including intangible assets) based upon their fair values. The excess of the purchase price over the fair values of assets and liabilities is recorded as goodwill.

Regulated Delivery segment		Refers to the EFH Corp. business segment, the substantial majority of which consists of the activities of Oncor.

REP		retail electric provider

RRC		Railroad Commission of Texas, which among other things, has oversight of lignite mining activity in Texas

S&P		Standard & Poor’s Ratings Services, a division of the McGraw Hill Companies Inc. (a credit rating agency)

SEC		US Securities and Exchange Commission

SG&A		selling, general and administrative

Sponsor Group		Collectively, the investment funds affiliated with Kohlberg Kravis Roberts & Co. L.P. (KKR), TPG Capital, L.P. and GS Capital Partners, an affiliate of Goldman Sachs & Co. (See Texas Holdings below.)

TCEH		Refers to Texas Competitive Electric Holdings Company LLC, a direct, wholly-owned subsidiary of EFC Holdings and an indirect subsidiary of EFH Corp., and/or its subsidiaries, depending on context, that is engaged in electricity generation, wholesale and retail energy markets and development and construction activities. Its major subsidiaries include Luminant and TXU Energy.

TCEH Finance		Refers to TCEH Finance, Inc., a direct, wholly-owned subsidiary of TCEH, formed for the sole purpose of serving as co-issuer with TCEH of certain debt securities.

TCEH Senior Notes		Refers collectively to TCEH’s 10.25% Senior Notes due November 1, 2015 and 10.25% Senior Notes Series B due November 1, 2015 (collectively, TCEH Cash-Pay Notes) and TCEH’s 10.50%/11.25% Senior Toggle Notes due November 1, 2016 (TCEH Toggle Notes).

TCEH Senior Secured Facilities		Refers collectively to the TCEH Initial Term Loan Facility, TCEH Delayed Draw Term Loan Facility, TCEH Revolving Credit Facility, TCEH Letter of Credit Facility and TCEH Commodity Collateral Posting Facility. See Note 4 to Financial Statements for details of these facilities.


TCEQ		Texas Commission on Environmental Quality

Texas Holdings		Refers to Texas Energy Future Holdings Limited Partnership, a limited partnership controlled by the Sponsor Group that owns substantially all of the common stock of EFH Corp.

Texas Holdings Group		Refers to Texas Holdings and its direct and indirect subsidiaries other than the Oncor Ring-Fenced Entities.

Texas Transmission		Refers to Texas Transmission Investment LLC, a limited liability company that owns a 19.75% equity interest in Oncor. Texas Transmission is not affiliated with EFH Corp., any of its subsidiaries or any member of the Sponsor Group.

TXU Energy		Refers to TXU Energy Retail Company LLC, a direct, wholly-owned subsidiary of TCEH engaged in the retail sale of electricity to residential and business customers. TXU Energy is a REP in competitive areas of ERCOT.

TXU Gas		TXU Gas Company, a former subsidiary of EFH Corp.

US		United States of America

PART I. FINANCIAL INFORMATION

Item 1.

FINANCIAL STATEMENTS

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED INCOME (LOSS)

(Unaudited)

(millions of dollars)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
Operating revenues	$	2,885		$	3,695		$	7,366		$	9,001
Fuel, purchased power costs and delivery fees		(870	)		(1,631	)		(2,171	)		(3,867	)
Net gain (loss) from commodity hedging and trading activities		123			6,045			1,003			(248	)
Operating costs		(388	)		(370	)		(1,171	)		(1,120	)
Depreciation and amortization		(456	)		(431	)		(1,286	)		(1,217	)
Selling, general and administrative expenses		(277	)		(249	)		(792	)		(712	)
Franchise and revenue-based taxes		(94	)		(92	)		(259	)		(259	)
Impairment of goodwill (Note 2)		—			—			(90	)		—
Other income (Note 13)		45			14			71			43
Other deductions (Note 13)		(32	)		(541	)		(50	)		(583	)
Interest income		18			9			30			22
Interest expense and related charges (Note 13)		(1,039	)		(831	)		(2,136	)		(2,505	)


Income (loss) before income taxes		(85	)		5,618			515			(1,445	)

Income tax (expense) benefit		31			(2,001	)		(254	)		462


Net income (loss)		(54	)		3,617			261			(983	)

Net income attributable to noncontrolling interests		(26	)		—			(54	)		—


Net income (loss) attributable to EFH Corp.	$	(80	)	$	3,617		$	207		$	(983	)

See Notes to Financial Statements.

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)

(Unaudited)

(millions of dollars)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
Net income (loss)	$	(54	)	$	3,617		$	261		$	(983	)

Other comprehensive income (loss), net of tax effects:

Reclassification of pension and other retirement benefit costs (net of tax expense of $— in all periods)		—			—			—			1

Cash flow hedges:
Net decrease in fair value of derivatives (net of tax benefit of $2, $76, $11 and $99)		(4	)		(141	)		(20	)		(184	)
Derivative value net loss related to hedged transactions recognized during the period and reported in net income (loss) (net of tax benefit of $21, $22, $53 and $45)		41			42			99			84

Total effect of cash flow hedges		37			(99	)		79			(100	)


Total adjustments to net income (loss)		37			(99	)		79			(99	)


Comprehensive income (loss) operations		(17	)		3,518			340			(1,082	)

Comprehensive income attributable to noncontrolling interests		(26	)		—			(54	)		—


Comprehensive income (loss) attributable to EFH Corp.	$	(43	)	$	3,518		$	286		$	(1,082	)

See Notes to Financial Statements.

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Unaudited)

(millions of dollars)


	Nine Months Ended September 30,
	2009			2008
Cash flows – operating activities:
Net income (loss)	$	261		$	(983	)
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation and amortization		1,738			1,554
Deferred income tax expense (benefit)		152			(433	)
Impairment of goodwill (Note 2)		90			—
Write off of regulatory assets (Note 13)		25			—
Impairment of emission allowances intangible assets		—			501
Charge related to Lehman bankruptcy (Note 13)		—			26
Unrealized net (gains) losses from mark-to-market valuations of commodity positions		(713	)		221
Unrealized net gains from mark-to-market valuations of interest rate swaps		(527	)		(36	)
Bad debt expense		84			58
Stock-based incentive compensation expense		12			26
Reversal of use tax accrual (Note 13)		(23	)		—
Other – net		(4	)		18
Changes in operating assets and liabilities:
Margin deposits – net		260			(236	)
Deferred advanced metering system revenues (Note 13)		51			—
Other operating assets and liabilities		337			241

Cash provided by operating activities		1,743			957


Cash flows – financing activities:
Issuances of long-term debt/securities
Pollution control revenue bonds		—			242
Other long-term debt (Note 4)		522			2,535
Common stock		—			34
Repayments/repurchases of long-term debt/securities:
Pollution control revenue bonds		—			(242	)
Other long-term debt (Note 4)		(297	)		(432	)
Common stock		—			(1	)
Increase in short-term borrowings (Note 4)		200			902
Contributions from noncontrolling interests		42			—
Distributions paid to noncontrolling interests		(32	)		—
Debt discount, financing and reacquisition expenses		(36	)		(19	)
Other – net		21			33

Cash provided by financing activities		420			3,052


Cash flows – investing activities:
Capital expenditures		(1,847	)		(2,067	)
Nuclear fuel purchases		(157	)		(112	)
Money market fund redemptions (investments)		142			(242	)
Investment posted with derivative counterparty (Note 7)		(400	)		—
Reduction of restricted cash related to pollution control revenue bonds		—			29
Reduction of restricted cash related to letter of credit facility (Note 4)		115			—
Transfer of cash collateral from (to) custodian account		3			(20	)
Net proceeds from sale of assets		1			53
Net proceeds from sale of controlling interest in natural gas gathering pipeline business		40			—
Proceeds from sales of environmental allowances and credits		22			30
Purchases of environmental allowances and credits		(23	)		(18	)
Proceeds from sales of nuclear decommissioning trust fund securities		2,972			747
Investments in nuclear decommissioning trust fund securities		(2,983	)		(758	)
Cost to remove retired property		(30	)		(26	)
Other		18			10

Cash used in investing activities		(2,127	)		(2,374	)

Net change in cash and cash equivalents		36			1,635
Cash and cash equivalents – beginning balance		1,689			281

Cash and cash equivalents – ending balance	$	1,725		$	1,916

See Notes to Financial Statements.

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(millions of dollars)


	September 30, 2009			December 31, 2008
ASSETS
Current assets:
Cash and cash equivalents	$	1,725		$	1,689
Investment posted with counterparty (Note 7)		417			—
Investments held in money market fund		—			142
Restricted cash (Note 13)		64			55
Trade accounts receivable – net (Note 3)		1,014			1,219
Income taxes receivable – net		—			42
Inventories (Note 13)		484			426
Commodity and other derivative contractual assets (Note 7)		2,619			2,534
Accumulated deferred income taxes		101			44
Margin deposits related to commodity positions		158			439
Other current assets		145			165

Total current assets		6,727			6,755


Restricted cash (Note 13)		1,150			1,267
Investments (Note 13)		744			645
Property, plant and equipment – net (Note 13)		30,019			29,522
Goodwill (Note 2)		14,316			14,386
Intangible assets – net (Note 2)		2,907			2,993
Regulatory assets – net (Note 13)		1,755			1,892
Commodity and other derivative contractual assets (Note 7)		1,153			962
Other noncurrent assets, principally unamortized debt issuance costs		880			841

Total assets	$	59,651		$	59,263


LIABILITIES AND EQUITY
Current liabilities:
Short-term borrowings (Note 4)	$	1,437		$	1,237
Long-term debt due currently (Note 4)		326			385
Trade accounts payable		738			1,143
Commodity and other derivative contractual liabilities (Note 7)		2,649			2,908
Margin deposits related to commodity positions		504			525
Accrued interest		856			524
Other current liabilities		694			612

Total current liabilities		7,204			7,334


Accumulated deferred income taxes		6,063			5,926
Investment tax credits		38			42
Commodity and other derivative contractual liabilities (Note 7)		1,343			2,095
Long-term debt, less amounts due currently (Note 4)		41,442			40,838
Other noncurrent liabilities and deferred credits (Note 13)		5,375			5,205

Total liabilities		61,465			61,440
Commitments and Contingencies (Note 5)

Equity (Note 6):

EFH Corp. shareholders’ equity		(3,234	)		(3,532	)
Noncontrolling interests in subsidiaries		1,420			1,355

Total equity		(1,814	)		(2,177	)

Total liabilities and equity	$	59,651		$	59,263

See Notes to Financial Statements.

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1.	BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES

Description of Business

EFH Corp., a Texas corporation, is a Dallas-based holding company conducting its operations principally through its TCEH and Oncor subsidiaries. TCEH is a holding company for subsidiaries engaged in competitive electricity market activities largely in Texas, including electricity generation, development and construction of new generation facilities, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity sales. Oncor is a majority (approximately 80%) owned subsidiary engaged in regulated electricity transmission and distribution operations in Texas.

References in this report to “we,” “our,” “us” and “the company” are to EFH Corp. and/or its subsidiaries, TCEH and/or its subsidiaries, or Oncor and/or its subsidiary as apparent in the context. See “Glossary” for other defined terms.

Various “ring-fencing” measures have been taken to enhance the credit quality of Oncor. Such measures include, among other things: the sale of a 19.75% equity interest in Oncor to Texas Transmission in November 2008; maintenance of separate books and records for the Oncor Ring-Fenced Entities; Oncor’s board of directors being comprised of a majority of independent directors, and prohibitions on the Oncor Ring-Fenced Entities providing credit support to, or receiving credit support from, any member of the Texas Holdings Group. The assets and liabilities of the Oncor Ring-Fenced Entities are separate and distinct from those of the Texas Holdings Group and none of the assets of the Oncor Ring-Fenced Entities are available to satisfy the debt or other obligations of any member of the Texas Holdings Group. Moreover, Oncor’s operations are conducted, and its cash flows managed, independently from the Texas Holdings Group. Oncor Holdings is consolidated with EFH Corp. as a variable interest entity under consolidations accounting standards.

We have two reportable segments: the Competitive Electric segment, which is comprised principally of TCEH, and the Regulated Delivery segment, which is comprised of Oncor and its wholly-owned bankruptcy-remote financing subsidiary. See Note 12 for further information concerning reportable business segments.

Basis of Presentation

The condensed consolidated financial statements have been prepared in accordance with US GAAP and on the same basis as the audited financial statements included in the 2008 Form 10-K, with the exception of the adoption of new accounting and disclosure guidance related to derivative instruments and hedging activities, subsequent events and reporting of fair value as discussed below. All adjustments (consisting of normal recurring accruals) necessary for a fair presentation of the results of operations and financial position have been included therein. All intercompany items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with US GAAP have been omitted pursuant to the rules and regulations of the SEC. Because the condensed consolidated interim financial statements do not include all of the information and footnotes required by US GAAP, they should be read in conjunction with the audited financial statements and related notes included in the 2008 Form 10-K. The results of operations for an interim period may not give a true indication of results for a full year. All dollar amounts in the financial statements and tables in the notes are stated in millions of US dollars unless otherwise indicated. Subsequent events have been evaluated through October 29, 2009, the date these condensed consolidated financial statements were issued.

Use of Estimates

Preparation of the financial statements requires estimates and assumptions about future events that affect the reporting of assets and liabilities at the balance sheet dates and the reported amounts of revenue and expense, including fair value measurements. In the event estimates and/or assumptions prove to be different from actual amounts, adjustments are made in subsequent periods to reflect more current information. No material adjustments, other than those disclosed elsewhere herein, were made to previous estimates or assumptions during the current year.

Changes in Accounting Standards

In August 2009, the FASB issued guidance on measuring fair value of liabilities, which provides clarification of fair value measurement when there is limited or no observable data available. This new guidance is effective for periods beginning October 1, 2009. We are evaluating the impact of this new guidance, but currently do not expect a material effect on our financial statements.

In June 2009, the FASB issued “The FASB Accounting Standards Codification™ and the Hierarchy of Generally Accepted Accounting Principles,” which establishes the FASB Accounting Standards Codification™ (Codification) as the source of authoritative US GAAP recognized by the FASB to be applied to nongovernmental entities. The Codification was effective for financial statements issued for interim and annual periods ending after September 15, 2009. The adoption of the Codification did not affect reported results of operations, financial condition or cash flows. We implemented the Codification in this Form 10-Q.

In June 2009, the FASB issued new guidance that (i) changes how a reporting entity determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated and (ii) requires additional disclosures. This new guidance is effective for periods beginning after November 15, 2009. We are evaluating the impact of this new guidance, but currently do not expect a material effect on our financial statements.

In June 2009, the FASB issued new guidance regarding accounting for transfers of financial assets that eliminates the concept of a qualifying special purpose entity, changes the requirements for derecognizing financial assets and requires additional disclosures. This new guidance is effective in the first quarter of 2010. We continue to evaluate the impact of this new guidance on our financial statements and footnote disclosures; however, we currently expect that our accounts receivable securitization program discussed in Note 3 will no longer be accounted for as a sale of accounts receivable as a result of the guidance, and the funding under the program will be reported as short-term borrowings. This new guidance will not impact the covenant-related ratio calculations in our debt agreements.

In May 2009, the FASB issued new guidance related to subsequent events that requires disclosure of the date through which we have evaluated subsequent events related to the financial statements being issued and the basis for that date. This guidance was effective for interim and annual reporting periods ending after June 15, 2009. Our adoption of this guidance as of April 1, 2009 did not affect reported results of operations, financial condition or cash flows, and the required disclosure is provided above in “Basis of Presentation.”

In April 2009, the FASB issued new guidance regarding determining fair value when the volume and level of activity for the asset or liability have significantly decreased and identifying transactions that are not orderly. This guidance was effective for interim reporting periods ending after June 15, 2009, and we adopted it as of April 1, 2009. This guidance did not change our fair value measurement techniques. However, this guidance requires disclosures of additional detail of securities held in our nuclear decommissioning trust that are provided in Notes 8 and 13.

In April 2009, the FASB issued new guidance regarding the recognition and presentation of other-than-temporary impairments, which changed the guidance for recording impairment of investments in debt securities. This guidance was effective for interim and annual reporting periods ending after June 15, 2009, and is expected to affect many utility companies that hold debt securities in nuclear decommissioning trust funds. However, our adoption as of April 1, 2009 did not affect the accounting for our nuclear decommissioning trust fund because the trust balance is reported at fair value, with changes in fair value of the trust resulting in changes in Oncor’s regulatory asset or liability related to the decommissioning cost. This new guidance also requires the disclosure of information about the fair value of the investments for interim reporting as provided in Note 13.

In April 2009, the FASB issued new guidance requiring the disclosure of summarized financial information about the fair value of financial instruments for interim reporting. This new guidance was effective for interim reporting periods ending after June 15, 2009, and we adopted it as of April 1, 2009. As this new guidance provides only disclosure requirements, the adoption did not have any effect on reported results of operations, financial condition or cash flows. The disclosures are provided in Note 9.

In December 2008, the FASB issued new guidance for employers’ disclosures about postretirement benefit plan assets. This new guidance provides enhanced disclosures regarding how investment allocation decisions are made and certain aspects of fair value measurements on plan assets. The required disclosures are intended to provide transparency related to the types of assets and associated risks in an employer’s defined benefit pension or other postretirement employee benefits plan and events in the economy and markets that could have a significant effect on the value of plan assets. These new disclosure requirements are effective for fiscal years ending after December 15, 2009. As this new guidance provides only disclosure requirements, the adoption will not have any effect on reported results of operations, financial condition or cash flows.

In March 2008, the FASB issued amended disclosure guidance for derivative instruments and hedging activities. This amended guidance enhances required disclosures regarding derivatives and hedging activities to enable investors to better understand their effects on an entity’s financial position, financial performance and cash flows. This guidance was effective with reporting for the three months ended March 31, 2009. As this guidance provides only disclosure requirements, the adoption did not have any effect on reported results of operations or financial condition. The disclosures are provided in Note 7.

In December 2007, the FASB issued amended guidance for accounting for noncontrolling interests in consolidated financial statements effective for fiscal years beginning on or after December 15, 2008. This amended guidance requires noncontrolling interests in subsidiaries initially to be measured at fair value and classified as a separate component of equity. Effective January 1, 2009, on a retrospective basis, we classified the noncontrolling interests created as a result of Oncor’s November 2008 sale of equity interests ($1.355 billion as of December 31, 2008) and those created as part of the nuclear generation development joint venture formed in the first quarter of 2009 as a separate component of equity in the balance sheet, and reported consolidated net income (loss) includes the net income attributable to noncontrolling interests.

2.	GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS

Goodwill

Reported goodwill as of September 30, 2009 totaled $14.3 billion, with $10.2 billion assigned to the Competitive Electric segment and $4.1 billion to the Regulated Delivery segment. Reported goodwill as of December 31, 2008 totaled $14.4 billion, with $10.3 billion assigned to the Competitive Electric segment and $4.1 billion to the Regulated Delivery segment. None of this goodwill balance is being deducted for tax purposes.

In the first quarter of 2009, we recorded a $90 million goodwill impairment charge largely related to the Competitive Electric segment. This charge resulted from the completion of fair value calculations supporting the initial $8.860 billion goodwill impairment charge that was recorded in the fourth quarter of 2008. The impairment charge primarily reflected the dislocation in the capital markets during the fourth quarter of 2008 that increased interest rate spreads and the resulting discount rates used in estimating fair values and the effect of declines in market values of debt and equity securities of comparable companies. The impairment determination involved significant assumptions and judgments in estimating enterprise values of the Competitive Electric and Regulated Delivery segments and the fair values of their assets and liabilities. There have been no other goodwill impairments recorded since the Merger.

The calculations supporting the impairment determination utilized models that take into consideration multiple inputs, including commodity prices, debt yields, equity prices of comparable companies and other inputs. Those models were generally used in developing long-term forward price curves for certain commodities and discount rates for determining fair values of our reporting units as well as certain individual assets and liabilities of those businesses. The fair value measurements resulting from such models are classified as Level 3 measurements consistent with accounting standards related to the determination of fair value (see Note 8).

Identifiable Intangible Assets

Identifiable intangible assets reported in the balance sheet are comprised of the following:


	As of September 30, 2009						As of December 31, 2008
	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
Retail customer relationship	$	463	$	194	$	269	$	463	$	130	$	333
Favorable purchase and sales contracts		700		340		360		700		249		451
Capitalized in-service software		445		153		292		255		116		139
Environmental allowances and credits		988		187		801		994		121		873
Land easements and other		203		75		128		203		71		132

Total intangible assets subject to amortization	$	2,799	$	949		1,850	$	2,615	$	687		1,928

Trade name (not subject to amortization)						955						955
Mineral interests (not currently subject to amortization)						102						110

Total intangible assets					$	2,907					$	2,993

Amortization expense related to intangible assets consisted of:


		Three Months Ended September 30,				Nine Months Ended September 30,
Intangible Asset (Income Statement line)	Segment	2009		2008		2009		2008
Retail customer relationship (Depreciation and amortization)	Competitive Electric	$	21	$	13	$	64	$	39
Favorable purchase and sales contracts (Operating revenues/ fuel, purchased power costs and delivery fees)	Competitive Electric		18		9		91		115
Capitalized in-service software (Depreciation and amortization)	All		16		11		39		33
Environmental allowances and credits (Fuel, purchased power costs and delivery fees)	Competitive Electric		25		28		66		77
Land easements and other (Depreciation and amortization)	All		2		1		4		2

Total amortization expense		$	82	$	62	$	264	$	266

Estimated Amortization of Intangible Assets — The estimated aggregate amortization expense related to identifiable intangible assets for each of the next five fiscal years is as follows:


Year	Amount
2009	$	365
2010		265
2011		205
2012		161
2013		135

3.	TRADE ACCOUNTS RECEIVABLE AND SALE OF RECEIVABLES PROGRAM

TXU Energy participates in an accounts receivable securitization program, the activity under which is accounted for as a sale of accounts receivable in accordance with transfers and servicing accounting standards (see Note 1 for discussion of a new accounting standard effective in the first quarter of 2010). Under the program, TXU Energy (originator) sells trade accounts receivable to TXU Receivables Company, which is a special purpose entity created for the purpose of purchasing receivables from the originator and is a consolidated wholly-owned bankruptcy-remote direct subsidiary of EFH Corp. TXU Receivables Company sells undivided interests in the purchased accounts receivable for cash to special purpose entities established by financial institutions (the funding entities).

Program funding totaled $700 million at September 30, 2009, the maximum amount currently available under the accounts receivable securitization program.

All new trade receivables under the program generated by the originator are continuously purchased by TXU Receivables Company with the proceeds from collections of receivables previously purchased. Changes in the amount of funding under the program, through changes in the amount of undivided interests sold by TXU Receivables Company, reflect seasonal variations in the level of accounts receivable, changes in collection trends and other factors such as changes in sales prices and volumes. TXU Receivables Company has issued subordinated notes payable to the originator for the difference between the face amount of the uncollected accounts receivable purchased, less a discount, and cash paid to the originator that was funded by the sale of the undivided interests. The balance of the subordinated notes payable, which is eliminated in consolidation, totaled $489 million and $268 million at September 30, 2009 and December 31, 2008, respectively.

The discount from face amount on the purchase of receivables from the originator principally funds program fees paid to the funding entities. The program fees, which are also referred to as losses on sale of the receivables under transfers and servicing accounting standards, consist primarily of interest costs on the underlying financing. The discount also funds a servicing fee paid by TXU Receivables Company to EFH Corporate Services Company, a direct wholly-owned subsidiary of EFH Corp., which provides recordkeeping services and is the collection agent for the program.

Program fee amounts, which are reported in SG&A expenses, were as follows:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
Program fees	$	2		$	7		$	9		$	18
Program fees as a percentage of average funding (annualized)		1.3	%		4.2	%		2.4	%		5.2	%

The trade accounts receivable balance reported in the September 30, 2009 consolidated balance sheet includes $1.189 billion face amount of retail accounts receivable sold and has been reduced by proceeds from the sale of undivided interests in those receivables totaling $700 million. Funding under the program increased $284 million and $337 million for the nine month periods ending September 30, 2009 and 2008, respectively. Funding increases or decreases under the program are reflected as operating cash flow activity in the statement of cash flows. The carrying amount of the retained interests in the accounts receivable balance approximated fair value due to the short-term nature of the collection period.

Activities of TXU Receivables Company were as follows:


	Nine Months Ended September 30,
	2009			2008
Cash collections on accounts receivable	$	4,660		$	4,881
Face amount of new receivables purchased		(5,165	)		(5,263	)
Discount from face amount of purchased receivables (to fund fees paid)		11			22
Program fees paid to funding entities		(9	)		(18	)
Servicing fees paid to EFH Corp. subsidiary for recordkeeping and collection services		(2	)		(3	)
Increase in subordinated notes payable		221			44

Operating cash flows provided to originator under the program	$	(284	)	$	(337	)

The program, which expires in October 2013, may be terminated upon the occurrence of a number of specified events, including if the delinquency ratio (delinquent for 31 days) for the sold receivables, the default ratio (delinquent for 91 days or deemed uncollectible), the dilution ratio (reductions for discounts, disputes and other allowances) or the days collection outstanding ratio exceed stated thresholds, and the funding entities do not waive such event of termination. The thresholds apply to the entire portfolio of sold receivables. In addition, the program may be terminated if TXU Receivables Company or the EFH Corp. subsidiary acting as collection agent defaults in any payment with respect to debt in excess of $50,000 in the aggregate for such entities, or if TCEH, any affiliate of TCEH acting as collection agent other than the EFH Corp. subsidiary, any parent guarantor of the originator or the originator shall default in any payment with respect to debt (other than hedging obligations) in excess of $200 million in the aggregate for such entities. As of September 30, 2009, there were no such events of termination.

Upon termination of the program, cash flows would be delayed as collections of sold receivables would be used by TXU Receivables Company to repurchase the undivided interests from the funding entities instead of purchasing new receivables. The level of cash flows would normalize in approximately 16 to 30 days.

The subordinated notes issued by TXU Receivables Company are subordinated to the undivided interests of the funding entities in the purchased receivables.

Trade Accounts Receivable


	September 30, 2009			December 31, 2008
Gross wholesale and retail trade accounts receivable	$	1,800		$	1,705
Undivided interests in retail accounts receivable sold by TXU Receivables Company		(700	)		(416	)
Allowance for uncollectible accounts		(86	)		(70	)

Trade accounts receivable – reported in balance sheet	$	1,014		$	1,219

Gross trade accounts receivable at September 30, 2009 and December 31, 2008 included unbilled revenues of $526 million and $505 million, respectively.

Allowance for Uncollectible Accounts Receivable


	Nine Months Ended September 30,
	2009			2008
Allowance for uncollectible accounts receivable as of beginning of period	$	70		$	32
Increase for bad debt expense		84			58
Decrease for account write-offs		(67	)		(47	)
Charge related to Lehman bankruptcy		—			26
Other		(1	)		—

Allowance for uncollectible accounts receivable as of end of period	$	86		$	69

4.	SHORT-TERM BORROWINGS AND LONG-TERM DEBT

Short-Term Borrowings

At September 30, 2009, we had outstanding short-term borrowings of $1.437 billion at a weighted average interest rate of 2.60%, excluding certain customary fees, at the end of the period. Short-term borrowings under credit facilities totaled $900 million for TCEH and $537 million for Oncor.

At December 31, 2008, we had outstanding short-term borrowings of $1.237 billion at a weighted average interest rate of 3.41%, excluding certain customary fees, at the end of the period. Short-term borrowings under credit facilities totaled $900 million for TCEH and $337 million for Oncor.

Credit Facilities

Our credit facilities with cash borrowing and/or letter of credit availability at September 30, 2009 are presented below. The facilities are all senior secured facilities of the authorized borrower.


		At September 30, 2009
Authorized Borrowers and Facility	Maturity Date	Facility Limit		Letters of Credit		Cash Borrowings		Availability
TCEH Delayed Draw Term Loan Facility (a)	October 2014	$	4,100	$	—	$	4,085	$	—
TCEH Revolving Credit Facility (b)	October 2013		2,700		38		900		1,736
TCEH Letter of Credit Facility (c)	October 2014		1,250		—		1,250		—

Subtotal TCEH (d)		$	8,050	$	38	$	6,235	$	1,736

TCEH Commodity Collateral Posting Facility (e)	December 2012		Unlimited	$	—	$	—		Unlimited
Oncor Revolving Credit Facility (f)	October 2013	$	2,000	$	—	$	537	$	1,341

(a)

Facility was used to fund expenditures for constructing certain new generation facilities and environmental upgrades of existing generation facilities. Availability amount excludes $15 million of commitments from a subsidiary of Lehman Brothers Holding Inc. (such subsidiary, Lehman) that has filed for bankruptcy under Chapter 11 of the US Bankruptcy Code. Borrowings are classified as long-term debt.

(b)

Facility used for letters of credit and borrowings for general corporate purposes. Borrowings are classified as short-term borrowings. Availability amount includes $141 million of commitments from Lehman that are only available from the fronting banks and the swingline lender and excludes $26 million of requested cash draws that have not been funded by Lehman. All outstanding borrowings under this facility at September 30, 2009 bear interest at LIBOR plus 3.5%, and a commitment fee is payable quarterly in arrears at a rate per annum equal to 0.50% of the average daily unused portion of the facility.

(c)

Facility used for issuing letters of credit for general corporate purposes, including, but not limited to, providing collateral support under hedging arrangements and other commodity transactions that are not eligible for funding under the TCEH Commodity Collateral Posting Facility. The borrowings under this facility were drawn at the inception of the facility, are classified as long-term debt, and except for $115 million related to a letter of credit drawn in June 2009, have been retained as restricted cash. Letters of credit totaling $676 million issued as of September 30, 2009 are supported by the restricted cash, and the remaining letter of credit availability totals $459 million.

(d)

Pursuant to PUCT rules, TCEH is required to maintain available capacity under its credit facilities to assure adequate credit worthiness of TCEH’s REP subsidiaries, including the ability to return retail customer deposits, if necessary. As a result, at September 30, 2009, the total availability under the TCEH credit facilities should be further reduced by $237 million.

(e)

Revolving facility used to fund cash collateral posting requirements for specified volumes of natural gas hedges totaling approximately 650 million MMBtu as of September 30, 2009. As of September 30, 2009, there were no borrowings under this facility. See “TCEH Senior Secured Facilities” below for additional information.

(f)

Facility used by Oncor for its general corporate purposes. Borrowings are classified as short-term borrowings. Availability amount excludes $122 million of commitments from Lehman. All outstanding borrowings under this facility at September 30, 2009 bear interest at LIBOR plus 0.350%, and a facility fee is payable (currently at a rate per annum equal to 0.125%) on the commitments under the facility. The interest rate and facility fee rate per annum declined in June 2009 from LIBOR plus 0.425% and 0.150%, respectively, due to a two notch upgrade in Oncor’s credit ratings by Moody’s.

Long-Term Debt

At September 30, 2009 and December 31, 2008, long-term debt consisted of the following:


	September 30, 2009			December 31, 2008
TCEH
Pollution Control Revenue Bonds:
Brazos River Authority:
5.400% Fixed Series 1994A due May 1, 2029	$	39		$	39
7.700% Fixed Series 1999A due April 1, 2033		111			111
6.750% Fixed Series 1999B due September 1, 2034, remarketing date April 1, 2013 (a)		16			16
7.700% Fixed Series 1999C due March 1, 2032		50			50
8.250% Fixed Series 2001A due October 1, 2030		71			71
5.750% Fixed Series 2001C due May 1, 2036, remarketing date November 1, 2011 (a)		217			217
8.250% Fixed Series 2001D-1 due May 1, 2033		171			171
0.450% Floating Series 2001D-2 due May 1, 2033 (b)		97			97
0.340% Floating Taxable Series 2001I due December 1, 2036 (c)		62			62
0.450% Floating Series 2002A due May 1, 2037 (b)		45			45
6.750% Fixed Series 2003A due April 1, 2038, remarketing date April 1, 2013 (a)		44			44
6.300% Fixed Series 2003B due July 1, 2032		39			39
6.750% Fixed Series 2003C due October 1, 2038		52			52
5.400% Fixed Series 2003D due October 1, 2029, remarketing date October 1, 2014 (a)		31			31
5.000% Fixed Series 2006 due March 1, 2041		100			100

Sabine River Authority of Texas:
6.450% Fixed Series 2000A due June 1, 2021		51			51
5.500% Fixed Series 2001A due May 1, 2022, remarketing date November 1, 2011 (a)		91			91
5.750% Fixed Series 2001B due May 1, 2030, remarketing date November 1, 2011 (a)		107			107
5.200% Fixed Series 2001C due May 1, 2028		70			70
5.800% Fixed Series 2003A due July 1, 2022		12			12
6.150% Fixed Series 2003B due August 1, 2022		45			45

Trinity River Authority of Texas:
6.250% Fixed Series 2000A due May 1, 2028		14			14

Unamortized fair value discount related to pollution control revenue bonds (d)		(150	)		(161	)

Senior Secured Facilities:
3.754% TCEH Initial Term Loan Facility maturing October 10, 2014 (e)(f)		16,121			16,244
3.754% TCEH Delayed Draw Term Loan Facility maturing October 10, 2014 (e)(f)		4,085			3,562
3.754% TCEH Letter of Credit Facility maturing October 10, 2014 (f)		1,250			1,250
0.243% TCEH Commodity Collateral Posting Facility maturing December 31, 2012 (g)		—			—

Other:
10.25% Fixed Senior Notes due November 1, 2015		3,000			3,000
10.25% Fixed Senior Notes Series B due November 1, 2015		2,000			2,000
10.50 / 11.25% Senior Toggle Notes due November 1, 2016		1,848			1,750
7.000% Fixed Senior Notes due March 15, 2013		5			5
7.100% Promissory Note due January 5, 2009		—			65
7.460% Fixed Secured Facility Bonds with amortizing payments through January 2015		55			67
Capital lease obligations		158			159
Unamortized fair value discount (d)		(5	)		(6	)

Total TCEH	$	29,902		$	29,470


	September 30, 2009			December 31, 2008
EFC Holdings
9.580% Fixed Notes due in semiannual installments through December 4, 2019	$	55		$	55
8.254% Fixed Notes due in quarterly installments through December 31, 2021		51			53
1.283% Floating Rate Junior Subordinated Debentures, Series D due January 30, 2037 (f)		1			1
8.175% Fixed Junior Subordinated Debentures, Series E due January 30, 2037		8			8
Unamortized fair value discount (d)		(12	)		(12	)

Total EFC Holdings		103			105


EFH Corp. (parent entity)
10.875% Fixed Senior Notes due November 1, 2017		2,000			2,000
11.25 / 12.00% Senior Toggle Notes due November 1, 2017		2,650			2,500
4.800% Fixed Senior Notes Series O due November 15, 2009		3			3
5.550% Fixed Senior Notes Series P due November 15, 2014		1,000			1,000
6.500% Fixed Senior Notes Series Q due November 15, 2024		750			750
6.550% Fixed Senior Notes Series R due November 15, 2034		750			750
8.820% Building Financing due semiannually through February 11, 2022 (h)		75			80
Unamortized fair value premium related to Building Financing (d)		17			22
Unamortized fair value discount (d)		(619	)		(661	)

Total EFH Corp.		6,626			6,444

Oncor (i)
6.375% Fixed Senior Notes due May 1, 2012		700			700
5.950% Fixed Senior Notes due September 1, 2013		650			650
6.375% Fixed Senior Notes due January 15, 2015		500			500
6.800% Fixed Senior Notes due September 1, 2018		550			550
7.000% Fixed Debentures due September 1, 2022		800			800
7.000% Fixed Senior Notes due May 1, 2032		500			500
7.250% Fixed Senior Notes due January 15, 2033		350			350
7.500% Fixed Senior Notes due September 1, 2038		300			300
Unamortized discount		(15	)		(16	)

Total Oncor		4,335			4,334

Oncor Electric Delivery Transition Bond Company LLC (j)
4.030% Fixed Series 2003 Bonds due in semiannual installments through February 15, 2010		13			54
4.950% Fixed Series 2003 Bonds due in semiannual installments through February 15, 2013		130			130
5.420% Fixed Series 2003 Bonds due in semiannual installments through August 15, 2015		145			145
3.520% Fixed Series 2004 Bonds due in semiannual installments through November 15, 2009		10			39
4.810% Fixed Series 2004 Bonds due in semiannual installments through November 15, 2012		221			221
5.290% Fixed Series 2004 Bonds due in semiannual installments through May 15, 2016		290			290

Total Oncor Electric Delivery Transition Bond Company LLC		809			879
Unamortized fair value discount related to transition bonds (d)		(7	)		(9	)

Total Oncor consolidated		5,137			5,204


Total EFH Corp. consolidated		41,768			41,223
Less amount due currently		(326	)		(385	)

Total long-term debt	$	41,442		$	40,838

(a)	These series are in the multiannual interest rate mode and are subject to mandatory tender prior to maturity on the mandatory remarketing date. On such date, the interest rate and interest rate period will be reset for the bonds.

(b)	Interest rates in effect at September 30, 2009. These series are in a daily interest rate mode and are classified as long-term as they are supported by long-term irrevocable letters of credit.

(c)	Interest rate in effect at September 30, 2009. This series is in a weekly interest rate mode and is classified as long-term as it is supported by long-term irrevocable letters of credit.

(d)	Amount represents unamortized fair value adjustments recorded under purchase accounting.

(e)	Interest rate swapped to fixed on $17.55 billion principal amount.

(f)	Interest rates in effect at September 30, 2009.

(g)	Interest rates in effect at September 30, 2009, excluding a quarterly maintenance fee of approximately $11 million. See “Credit Facilities” above for more information.

(h)

This financing is secured and will be serviced with $115 million in restricted cash drawn in June 2009 by the beneficiary of a letter of credit. The issuer elected not to extend the expiration date of the letter of credit, and TCEH elected to allow the drawing in lieu of reissuing the letter of credit under the TCEH Revolving Credit Facility. The remaining $104 million of the prepayment (net of $11 million of debt service payments) is included in other current assets and other noncurrent assets on the balance sheet.

(i)	Secured with first priority lien as discussed under “Oncor Revolving Credit Facility” below.

(j)	These bonds are nonrecourse to Oncor and were issued to securitize a regulatory asset.

Debt-Related Activity in 2009 — Repayments of long-term debt in 2009 totaling $297 million represented principal payments at scheduled maturity dates as well as other repayments totaling $39 million, principally related to capitalized leases. Payments at scheduled amortization or maturity dates included $123 million repaid under the TCEH Initial Term Loan Facility, $70 million of Oncor transition bond principal payments and $65 million of a TCEH promissory note.

Increases in long-term debt during 2009 totaling $522 million consisted of borrowings under the TCEH Delayed Draw Term Loan Facility, which was fully drawn as of July 2009, to fund expenditures related to construction of new generation facilities and environmental upgrades of existing lignite/coal-fueled generation facilities. In addition, long-term debt increased as a result of the issuance of $150 million of EFH Corp.’s 11.25%/12.00% Senior Toggle Notes due November 1, 2017 (EFH Corp. Toggle Notes) and $98 million of TCEH’s 10.50%/11.25% Senior Toggle Notes due November 1, 2016 (TCEH Toggle Notes) in lieu of cash interest payments as discussed below.

EFH Corp. and TCEH have the option every six months at their discretion, ending with the payment due November 1, 2012, to use the payment-in-kind (PIK) feature of their respective toggle notes in lieu of making cash interest payments. Once EFH Corp. and/or TCEH make a PIK election, the election is valid for each succeeding interest payment period until EFH Corp. and/or TCEH revoke the applicable election.

EFH Corp. made its May 2009 interest payment and will make its November 2009 and May 2010 interest payments by using the PIK feature of the EFH Corp. Toggle Notes. During the applicable interest periods, the interest rate on the toggle notes is increased from 11.25% to 12.00%. EFH Corp. increased the aggregate principal amount of the EFH Corp. Toggle Notes by $150 million on May 1, 2009 and will further increase the aggregate principal amount of the EFH Corp. Toggle Notes by $159 million on November 1, 2009 and $169 million on May 1, 2010. The elections increased liquidity as of May 1, 2009 by an amount equal to approximately $141 million and will further increase liquidity as of November 1, 2009 and May 1, 2010 by an amount equal to approximately $149 million and approximately $158 million, respectively, with such amounts constituting the amount of cash interest that otherwise would have been payable on the respective dates, and will increase the expected annual cash interest expense by approximately $54 million, constituting the additional cash interest that will be payable with respect to the $478 million of additional toggle notes. These amounts may be affected by the debt exchange offers discussed below.

Similarly, TCEH made its May 2009 interest payment and will make its November 2009 and May 2010 interest payments by using the PIK feature of the TCEH Toggle Notes. During the applicable interest periods, the interest rate on the toggle notes is increased from 10.50% to 11.25%. TCEH increased the aggregate principal amount of the TCEH Toggle Notes by $98 million on May 1, 2009 and will further increase the aggregate principal amount of the TCEH Toggle Notes by approximately $104 million on November 1, 2009 and $110 million on May 1, 2010. The elections increased liquidity as of May 1, 2009 by an amount equal to approximately $92 million and will further increase liquidity as of November 1, 2009 and May 1, 2010 by an amount equal to approximately $97 million and approximately $103 million, respectively, with such amounts constituting the amount of cash interest that otherwise would have been payable on the respective dates, and will increase the expected annual cash interest expense by approximately $33 million, constituting the additional cash interest that will be payable with respect to the $312 million of additional toggle notes.

Debt Exchange Offers and Consent Solicitations — In October 2009, EFH Corp., Intermediate Holding and EFIH Finance, a wholly-owned subsidiary of Intermediate Holding, (collectively, the Offerors) commenced offers to exchange certain EFH Corp. outstanding debt securities, consisting of the EFH Corp. Senior Notes and EFH Corp.’s Series P, Q and R notes (collectively, the EFH Corp. Securities), and the TCEH Cash-Pay Notes for up to $3.0 billion of new 9.75% senior secured notes due 2019 (new senior secured notes) to be issued by EFH Corp. ($1.35 billion) and Intermediate Holding and EFIH Finance ($1.65 billion), upon the terms and subject to certain conditions set forth in the prospectus relating to the exchange offers (Prospectus) and the related Consent and Letter of Transmittal. The purpose of the exchange offers is to reduce the outstanding principal amount and extend the weighted average maturity of the long-term debt of EFH Corp. and its subsidiaries. Under the terms of the exchange offers, the maximum principal amount of aggregate EFH Corp. Securities and TCEH Cash-Pay Notes that could be exchanged is approximately $4.9 billion.

Concurrent with the exchange offers, and upon the terms and subject to the conditions more fully described in the Prospectus and the related Consent and Letter of Transmittal, EFH Corp. is soliciting consents from holders of the EFH Corp. Securities to certain proposed amendments. The proposed amendments would eliminate substantially all of the restrictive covenants in the indentures governing the EFH Corp. Securities, eliminate certain events of default, modify covenants regarding mergers and consolidations, and modify or eliminate certain other provisions.

The exchange offers are not conditioned on any minimum principal amount of EFH Corp. Securities or TCEH Cash-Pay Notes being tendered or the issuance of a minimum principal amount of new senior secured notes or the receipt of requisite consents to adopt any of the proposed amendments to the indentures governing the EFH Corp. Securities. However, the exchange offers are subject to certain other conditions, including the conditions (which conditions cannot be waived) that the Registration Statement (as defined below), of which the Prospectus forms a part, has been declared effective by the SEC and that each series of the new senior secured notes to be issued in the exchange offers are approved for listing on the New York Stock Exchange, subject to notice of issuance, each as more fully described in the Prospectus. Subject to applicable law, the Offerors have the right to amend any of the exchange offers or the consent solicitations at any time and for any reason and to terminate or withdraw any of the exchange offers and consent solicitations if any of the conditions described in the Prospectus are not satisfied.

The Offerors filed a registration statement on Form S-4 (Registration Statement) relating to the exchange offers and the consent solicitations with the SEC on October 5, 2009 as amended on October 23, 2009. The Registration Statement has not yet become effective and the new senior secured notes may not be issued, nor may the exchange offers be completed, until such time as the Registration Statement has been declared effective by the SEC and is not subject to a stop order or any proceedings for that purpose. There is no assurance that the exchange offers and consent solicitations will be completed or that they will be completed on the terms and conditions described in the Prospectus.

TCEH Senior Secured Facilities — The applicable rate on borrowings under the TCEH Initial Term Loan Facility, the TCEH Delayed Draw Term Loan Facility, the TCEH Revolving Credit Facility and the TCEH Letter of Credit Facility as of September 30, 2009 is provided in the long-term debt table above and reflects LIBOR-based borrowings.

In August 2009, the Credit Agreement governing the TCEH Senior Secured Facilities was amended to reduce the existing first lien capacity under the TCEH Senior Secured Facilities by $1.25 billion in exchange for the ability for TCEH to issue up to an additional $4 billion of secured notes or loans ranking junior to TCEH’s first lien obligations, provided that:

•

such notes or loans mature later than the latest maturity date of any of the initial term loans under the TCEH Senior Secured Facilities, and

•

any net cash proceeds from any such issuances are used (i) in exchange for, or to refinance, repay, retire, refund or replace indebtedness of TCEH or (ii) to acquire, directly or indirectly, all or substantially all of the property and assets or business of another person or to finance the purchase price, cost of design, acquisition, construction, repair, restoration, replacement, expansion, installation or improvement of certain fixed or capital assets.

In addition, the amended Credit Agreement permits TCEH to, among other things:

•

issue new secured notes or loans, which may include, in each case, indebtedness secured on a pari passu basis with the obligations under the TCEH Senior Secured Facilities, so long as, in each case, among other things, the net cash proceeds from any such issuance are used to prepay certain loans under the TCEH Senior Secured Facilities at par;

•

agree with individual lenders to extend the maturity of their term loans or extend or refinance their revolving credit commitments under the TCEH Senior Secured Facilities, and pay increased interest rates or otherwise modify the terms of their loans or revolving commitments in connection with such an extension, and

•

exclude from the financial maintenance covenant under the TCEH Senior Secured Facilities any new debt issued that ranks junior to TCEH’s first lien obligations under the TCEH Senior Secured Facilities.

The TCEH Senior Secured Facilities are unconditionally guaranteed jointly and severally on a senior secured basis by EFC Holdings and subject to certain exceptions, each existing and future direct or indirect wholly-owned US restricted subsidiary of TCEH. The TCEH Senior Secured Facilities, including the guarantees thereof, certain commodity hedging transactions and the interest rate swaps described under “TCEH Interest Rate Hedges” below are secured by (a) substantially all of the current and future assets of TCEH and TCEH’s subsidiaries who are guarantors of such facilities and (b) pledges of the capital stock of TCEH and certain current and future direct or indirect subsidiaries of TCEH.

The TCEH Initial Term Loan Facility is required to be repaid in equal quarterly installments in an aggregate annual amount equal to 1% of the original principal amount of such facility (approximately $41 million quarterly), with the balance payable in October 2014. The TCEH Delayed Draw Term Loan Facility is required to be repaid in equal quarterly installments beginning in December 2009 in an aggregate annual amount equal to 1% of the actual principal outstanding under such facility as of such date, with the balance payable in October 2014. Amounts borrowed under the TCEH Revolving Facility may be reborrowed from time to time until October 2013. The TCEH Letter of Credit Facility and TCEH Commodity Collateral Posting Facility will mature in October 2014 and December 2012, respectively.

TCEH Senior Notes — Borrowings under TCEH’s and TCEH Finance’s (collectively, the Co-Issuers) 10.25% Senior Notes due November 1, 2015 and 10.25% Senior Notes Series B due November 1, 2015 (collectively, TCEH Cash-Pay Notes) bear interest semiannually in arrears on May 1 and November 1 of each year at a fixed rate of 10.25% per annum. Borrowings under the TCEH Toggle Notes bear interest semiannually in arrears on May 1 and November 1 of each year at a fixed rate of 10.50% per annum for cash interest and at a fixed rate of 11.25% per annum for PIK Interest (as defined below). For any interest period until November 1, 2012, the Co-Issuers may elect to pay interest on the notes (i) entirely in cash; (ii) by increasing the principal amount of the notes or by issuing new TCEH Toggle Notes (Payment-in-Kind or PIK Interest); or (iii) 50% in cash and 50% in PIK Interest.

The TCEH Cash-Pay Notes and the TCEH Toggle Notes (collectively, the TCEH Senior Notes) are fully and unconditionally guaranteed on a joint and several basis by TCEH’s direct parent, EFC Holdings (which owns 100% of TCEH and its subsidiary guarantors), and by each subsidiary that guarantees the TCEH Senior Secured Facilities.

The Co-Issuers may redeem the TCEH Cash-Pay Notes, in whole or in part, at any time on or after November 1, 2011, or the TCEH Toggle Notes, in whole or in part, at any time on or after November 1, 2012, at specified redemption prices, plus accrued and unpaid interest, if any. In addition, before November 1, 2010, the Co-Issuers may redeem with the cash proceeds of certain equity offerings up to 35% of the aggregate principal amount of TCEH Cash-Pay Notes and TCEH Toggle Notes from time to time at a redemption price of 110.250% and 110.500%, respectively, of their respective aggregate principal amount plus accrued and unpaid interest, if any. The Co-Issuers may also redeem the TCEH Cash-Pay Notes at any time prior to November 1, 2011 or the TCEH Toggle Notes at any time prior to November 1, 2012 at a price equal to 100% of their principal amount, plus accrued and unpaid interest and a “make-whole” premium. Upon the occurrence of a change in control of TCEH, the Co-Issuers must offer to repurchase the TCEH Senior Notes at 101% of their principal amount, plus accrued and unpaid interest, if any.

EFH Corp. Senior Notes — Borrowings under EFH Corp.’s 10.875% Senior Notes due November 1, 2017 (EFH Corp. Cash-Pay Notes) bear interest semiannually in arrears on May 1 and November 1 of each year at a fixed rate of 10.875% per annum. Borrowings under EFH Corp.’s 11.250%/12.000% Senior Toggle Notes due November 1, 2017 (EFH Corp. Toggle Notes and collectively with the EFH Corp. Cash-Pay Notes, the EFH Corp. Senior Notes) bear interest semiannually in arrears on May 1 and November 1 of each year at a fixed rate of 11.250% per annum for cash interest and at a fixed rate of 12.000% per annum for PIK Interest. For any interest period until November 1, 2012, EFH Corp. may elect to pay interest on the notes, at EFH Corp.’s option (i) entirely in cash; (ii) by increasing the principal amount of the notes or by issuing new EFH Corp. Toggle Notes; or (iii) 50% in cash and 50% in PIK Interest.

The EFH Corp. Senior Notes are fully and unconditionally guaranteed on a joint and several basis by EFC Holdings and Intermediate Holding.

EFH Corp. may redeem the EFH Corp. Senior Notes, in whole or in part, at any time on or after November 1, 2012, at specified redemption prices, plus accrued and unpaid interest, if any. In addition, before November 1, 2010, EFH Corp. may redeem, with the net cash proceeds of certain equity offerings, up to 35% of the aggregate principal amount of the EFH Corp. Toggle Notes from time to time at a redemption price of 110.875% of the aggregate principal amount of the EFH Corp. Cash-Pay Notes, plus accrued and unpaid interest, if any, or 111.250% of aggregate principal amount of the EFH Corp. Toggle Notes, plus accrued and unpaid interest, if any. EFH Corp. may also redeem the EFH Corp. Senior Notes at any time prior to November 1, 2012 at a price equal to 100% of their principal amount, plus accrued and unpaid interest and a “make-whole” premium. Upon the occurrence of a change in control of EFH Corp., EFH Corp. must offer to repurchase the EFH Corp. Senior Notes at 101% of their principal amount, plus accrued and unpaid interest, if any.

TCEH Interest Rate Swap Transactions — As of September 30, 2009, TCEH has entered into interest rate swap transactions pursuant to which payment of the floating interest rates on an aggregate of $17.55 billion of senior secured term loans of TCEH were exchanged for interest payments at fixed rates of between 7.3% and 8.3% on debt maturing from 2009 to 2014. Interest rate swaps on an aggregate of $15.05 billion were being accounted for as cash flow hedges related to variable interest rate cash flows until August 29, 2008, at which time these swaps were dedesignated as cash flow hedges as a result of the intent to change the variable interest rate terms of the hedged debt (from three-month LIBOR to one-month LIBOR) in connection with the planned execution of interest rate basis swaps (discussed immediately below) to further reduce the fixed borrowing costs. Based on the fair value of the positions, the cumulative unrealized mark-to-market net losses related to these interest rate swaps totaled $431 million (pre-tax) at the dedesignation date and was recorded in accumulated other comprehensive income. This balance will be reclassified into net income as interest on the hedged debt is reflected in net income. No ineffectiveness gains or losses were recorded.

As of September 30, 2009, TCEH has entered into interest rate basis swap transactions pursuant to which payments at floating interest rates of three-month LIBOR on an aggregate of $18.0 billion principal amount of senior secured term loans of TCEH were exchanged for floating interest rates of one-month LIBOR plus spreads ranging from 0.0625% to 0.353%. These transactions include swaps entered into in the nine months ended September 30, 2009 related to an aggregate $9.55 billion principal amount of senior secured term loans of TCEH and reflect the expiration of swaps in the nine months ended September 30, 2009 that related to an aggregate $4.595 billion principal amount of senior secured term loans of TCEH.

The interest rate swap counterparties are secured by the same collateral package granted to the lenders under the TCEH Senior Secured Facilities. Subsequent to the dedesignation in August 2008 discussed above, changes in the fair value of such swaps are being reported in the income statement in interest expense and related charges, and such unrealized mark-to-market value changes totaled $138 million in net losses and $36 million in net gains in the three months ended September 30, 2009 and 2008, respectively, and $527 million and $36 million in net gains in the nine months ended September 30, 2009 and 2008, respectively. The cumulative unrealized mark-to-market net liability related to the swaps totaled $1.4 billion at September 30, 2009, of which $238 million (pre-tax) was reported in accumulated other comprehensive income.

See Note 7 for discussion of collateral investments related to certain of these interest rate swaps.

Oncor Secured Revolving Credit Facility — Oncor has a $2.0 billion credit facility to be used for its working capital and general corporate purposes, including issuances of commercial paper and letters of credit. Oncor may request increases in the commitments under the facility in any amount up to $500 million, subject to the satisfaction of certain conditions. Amounts borrowed under the facility, once repaid, can be reborrowed by Oncor from time to time until October 10, 2013. Oncor secured this credit facility with a first priority lien on certain of its transmission and distribution assets. Oncor also secured all of its existing long-term debt securities (excluding the transition bonds) with the same lien in accordance with the terms of those securities. The lien contains customary provisions allowing Oncor to use the assets in its business, as well as to replace and/or release collateral as long as the market value of the aggregate collateral is at least 115% of the aggregate secured debt. The lien may be terminated at Oncor’s option upon the termination of Oncor’s credit facility. Borrowings under this credit facility totaled $537 million and $337 million at September 30, 2009 and December 31, 2008, respectively. The applicable rate on borrowings under this credit facility as of September 30, 2009 was 0.60% (see detail provided in the credit facilities table above).

5.	COMMITMENTS AND CONTINGENCIES

Generation Development

Construction of three lignite-fueled generation units in Texas, two units at Oak Grove and one unit at Sandow, is nearing completion. The Sandow unit achieved substantial completion (as defined in the EPC Agreement for the unit) on September 30, 2009, and one Oak Grove unit is in the commissioning and start-up phase.

In connection with the acquisition of the development rights to the Sandow unit, a subsidiary of TCEH (Sandow Power Company LLC, or Sandow Power) became a party to a federal consent decree with, among others, the US Department of Justice in August 2007 (the Consent Decree). A 2007 federal court order that was merged into the Consent Decree requires that, among other things, the Sandow unit commence commercial operation (as defined in the Consent Decree) and achieve and maintain certain emission-related deadlines by August 31, 2009. The Sandow unit met the commercial operation deadline by synchronizing to the ERCOT grid in early July 2009. However, due to unforeseen weather events and equipment malfunctions experienced during commissioning and start-up activities, the Sandow unit was not able to meet the emission-related deadlines by August 31, 2009. Under the terms of the Consent Decree, Sandow Power may request an extension to these deadlines from the federal district court that presides over the Consent Decree for certain force majeure events (including such events as the weather events and equipment malfunctions described above). In September 2009, the federal district court granted Sandow Power’s request for force majeure relief and gave Sandow Power an additional sixty-one days from August 31, 2009 to begin achieving compliance with the applicable Consent Decree deadlines.

TCEH has received the air permits for the Sandow and Oak Grove units. However, the issuances of the air permits have been challenged as discussed below under “Litigation Related to Generation Facilities.”

Construction work-in-process asset balances for the Oak Grove units totaled approximately $3.3 billion as of September 30, 2009, which includes the effects of the fair value adjustments related to purchase accounting and capitalized interest. In the unexpected event the development of the Oak Grove units was cancelled due to air permit challenges, the cancellation exposure as of September 30, 2009 totaled $3.4 billion, which includes the carrying value of the project and up to approximately $100 million of termination obligations. This estimated exposure amount excludes any potential recovery values for assets acquired to date and for assets already owned prior to executing such agreements that are being utilized in these projects.

Litigation Related to Generation Facilities

In September 2007, an administrative appeal challenging the order of the TCEQ issuing the air permit for construction and operation of the Oak Grove generation facility in Robertson County, Texas was filed in the State District Court of Travis County, Texas. Plaintiffs asked that the District Court reverse the TCEQ’s approval of the Oak Grove air permit and the TCEQ’s adoption and approval of the TCEQ Executive Director’s Response to Comments, and remand the matter back to TCEQ for further proceedings. In addition to this administrative appeal, two other petitions were filed in Travis County District Court by non-parties to the administrative hearing before the TCEQ and the State Office of Administrative Hearings (SOAH) seeking to challenge the TCEQ’s issuance of the Oak Grove air permit and asking the District Court to remand the matter to the SOAH for further proceedings. Finally, the plaintiffs in these two additional lawsuits filed a third, joint petition claiming insufficiencies in the Oak Grove application, permit, and process and seeking party status and remand to the SOAH for further proceedings. One of the plaintiffs has asked the District Court to consolidate all these proceedings, and the Attorney General of Texas, on behalf of TCEQ, filed pleas to the jurisdiction seeking dismissal of all but the administrative appeal. In May 2009, the District Court dismissed the claims that contest the merits of the TCEQ’s permitting decision, but declined to dismiss the claims that contest the process by which the TCEQ handled the permit application. Oak Grove Management Company LLC (a subsidiary of TCEH) has subsequently intervened in these proceedings and has filed its own pleas to the jurisdiction asking the court to dismiss the remaining collateral attack claims. In October 2009, one of the plaintiffs ended its legal challenge to the permit. We believe the Oak Grove air permit granted by the TCEQ was issued in accordance with applicable law. There can be no assurance that the outcome of these matters will not adversely impact the Oak Grove project.

In June and September 2008, administrative appeals were filed in the State District Court of Travis County, Texas to challenge the administrative action of the TCEQ Executive Director in issuing an air permit alteration for the previously-permitted construction and operation of the Sandow 5 generation facility in Milam County, Texas, and the failure of the TCEQ to overturn that administrative action. Plaintiffs asked that the District Court reverse the issuance of the permit alteration. The Attorney General of Texas, on behalf of TCEQ, is defending the issuance of the permit alteration. Sandow Power has intervened in support of the TCEQ. The plaintiff’s brief was filed in late August 2009, and the Attorney General of Texas and Sandow Power have filed responsive briefs. We believe the Sandow 5 air permit alteration administratively issued by the Executive Director of the TCEQ was issued in accordance with applicable law. There can be no assurance that the outcome of these matters will not adversely impact the Sandow 5 project.

In July 2008, the Sierra Club announced that it may sue Luminant, after the expiration of a 60-day waiting period, for violating federal Clean Air Act provisions in connection with Luminant’s Martin Lake generation facility. We cannot predict whether the Sierra Club will actually file suit relating to Martin Lake or the outcome of any such proceeding.

Other Litigation

In September 2005, a lawsuit was filed in the US District Court for the Northern District of Texas, Dallas Division against EFH Corp. (then known as TXU Corp.) and C. John Wilder, EFH Corp.’s former Chief Executive Officer. The plaintiffs asserted claims on behalf of themselves and a putative class of owners of certain EFH Corp. securities who tendered such securities in connection with a tender offer conducted by EFH Corp. in 2004. The plaintiffs alleged violations of the provisions of Sections 14(e), 10(b) and 20(a) of the Securities Exchange Act of 1934, as amended, and Rule 10b-5 thereunder. In August 2006, the District Court dismissed this litigation with prejudice. In 2007, the US Court of Appeals for the Fifth Circuit remanded the dismissal to the District Court in light of the US Supreme Court’s then-recent decision in Tellabs, Inc. v. Makor Issues & Rights, Ltd. On remand, in April 2008, the District Court again dismissed this litigation with prejudice. In April 2009, the US Court of Appeals for the Fifth Circuit affirmed the dismissal of all claims. In June 2009, the plaintiffs requested that the US Supreme Court review the merits of the case. In October 2009, the US Supreme Court denied the plaintiff’s petition for review. Accordingly, this litigation has concluded.

In July 2008, Alcoa Inc. filed a lawsuit in Milam County, Texas district court against Luminant Generation and Luminant Mining (wholly-owned subsidiaries of TCEH), later adding EFH Corp., a number of its subsidiaries, Texas Holdings and Texas Energy Future Capital Holdings LLC as parties to the suit. The lawsuit makes various claims concerning the operation of the Sandow Unit 4 generation facility and the Three Oaks lignite mine, including claims for breach of contract, breach of fiduciary duty, fraud, tortious interference, civil conspiracy and conversion. The plaintiff requests money damages of no less than $500 million, declaratory judgment, rescission and other forms of equitable relief. An agreed scheduling order is currently in place setting trial for May 2010. While we are unable to estimate any possible loss or predict the outcome of this litigation, we believe the plaintiff’s claims made in this litigation are without merit and, accordingly, intend to vigorously defend this litigation.

Regulatory Investigations and Reviews

In June 2008, the EPA issued a request for information to TCEH under EPA’s authority under Section 114 of the Clean Air Act. The stated purpose of the request is to obtain information necessary to determine compliance with the Clean Air Act, including New Source Review Standards and air permits issued by the TCEQ for the Big Brown, Monticello and Martin Lake generation facilities. The company is cooperating with the EPA and is responding in good faith to the EPA’s request, but is unable to predict the outcome of this matter.

Other Proceedings

In addition to the above, we are involved in various other legal and administrative proceedings in the normal course of business, the ultimate resolution of which, in the opinion of management, should not have a material effect on our financial position, results of operations or cash flows.

Guarantees

We have entered into contracts that contain guarantees to outside parties that could require performance or payment under certain conditions. Material guarantees are discussed below.

Disposed TXU Gas operations — In connection with the TXU Gas transaction in October 2004, EFH Corp. agreed to indemnify Atmos Energy Corporation (Atmos), until October 1, 2014, for up to $500 million for any liability related to assets retained by TXU Gas, including certain inactive gas plant sites not acquired by Atmos, and up to $1.4 billion for contingent liabilities associated with preclosing tax and employee related matters. The maximum aggregate amount that we may be required to pay is $1.9 billion. To date, we have not been required to make any payments to Atmos under any of these indemnity obligations, and no such payments are currently anticipated.

Residual value guarantees in operating leases — We are the lessee under various operating leases that guarantee the residual values of the leased assets. At September 30, 2009, the aggregate maximum amount of residual values guaranteed was approximately $51 million with an estimated residual recovery of approximately $56 million. These leased assets consist primarily of mining equipment, rail cars and vehicles. The average life of the residual value guarantees under the lease portfolio is approximately four years.

See Note 4 above and Note 15 to Financial Statements in the 2008 Form 10-K for discussion of guarantees and security for certain of our indebtedness.

Letters of Credit

At September 30, 2009, TCEH had outstanding letters of credit under its credit facilities totaling $714 million as follows:

•

$360 million to support risk management and trading margin requirements in the normal course of business, including over-the-counter hedging transactions;

•

$208 million to support floating rate pollution control revenue bond debt with an aggregate principal amount of $204 million (the letters of credit are available to fund the payment of such debt obligations and expire in 2014);

•

$65 million for collateral funding transactions with counterparties to interest rate swap agreements related to TCEH debt (see Note 7), and

•

$81 million for miscellaneous credit support requirements.

Long-Term Contractual Obligations and Commitments — In the nine months ended September 30, 2009, we entered into contractual obligations for fuel for our generation facilities totaling approximately $320 million to purchase nuclear fuel in periods between 2010 and 2020 and totaling approximately $153 million to purchase coal in periods between 2010 and 2012.

6.	EQUITY

Dividend Restrictions

The indenture governing the EFH Corp. Senior Notes includes covenants that, among other things and subject to certain exceptions, restrict our ability to pay dividends or make other distributions in respect of our capital stock. Accordingly, essentially all of our net income is restricted from being used to make distributions on our common stock unless such distributions are expressly permitted under the indenture and/or after such distributions, on a pro forma basis, after giving effect to such payment, our consolidated leverage ratio is equal to or less than 7.0 to 1.0. Consolidated leverage ratio is generally defined as the ratio of consolidated total indebtedness (as defined in the indenture) to Adjusted EBITDA, in each case, on a consolidated basis, excluding Oncor Holdings and its subsidiaries.

The TCEH Senior Secured Facilities generally restrict TCEH from making any distribution to any of its parent companies for the ultimate purpose of making a distribution to Texas Holdings unless at the time, and after giving effect to such distribution, its consolidated total debt (as defined in the TCEH Senior Secured Facilities) to Adjusted EBITDA would be equal to or less than 6.5 to 1.0. In addition, the TCEH Senior Secured Facilities and Indenture generally restrict TCEH’s ability to make distributions or loans to any of its parent companies, EFC Holdings and EFH Corp., unless such distributions or loans are expressly permitted under the TCEH Senior Secured Facilities and Indenture. Those agreements generally permit TCEH to make unlimited distributions or loans to its parent companies for corporate overhead costs, SG&A expenses, taxes and principal and interest payments. In addition, those agreements contain certain investment and dividend baskets that would allow TCEH to make additional distributions and/or loans to its parent companies up to the amount of such baskets. At September 30, 2009, EFH Corp. notes payable to TCEH totaled $1.112 billion.

In addition, under applicable law, we would be prohibited from paying any dividend to the extent that immediately following payment of such dividend, there would be no statutory surplus or we would be insolvent. See “Shareholder Actions” below.

EFH Corp. has not paid any cash dividends subsequent to the Merger.

Shareholder Actions

In May 2009, the shareholders of EFH Corp. approved the reduction of the stated capital of EFH Corp.’s common stock, no par value per share, to an amount equal to $0.001 for each outstanding share of common stock, resulting in total stated value of outstanding common stock of $2 million. Also in May 2009, EFH Corp.’s board of directors approved a decrease in additional paid-in capital of the same amount and the allocation of $0.001 per share to stated value of common stock upon issuance of any authorized but unissued shares of common stock that may occur from time to time, with the remainder of any amounts received for such shares allocated to additional paid-in capital.

Noncontrolling Interests

In November 2008, Oncor sold equity interests to Texas Transmission. Oncor also indirectly sold equity interests to certain members of its board of directors and its management team. Accordingly, after giving effect to all equity issuances, as of September 30, 2009, Oncor’s ownership was as follows: 80.03% held indirectly by EFH Corp., 0.22% held indirectly by Oncor’s management and board of directors and 19.75% held by Texas Transmission (see Note 1). Of the noncontrolling interests balance at September 30, 2009 in the table below, $1.378 billion related to Oncor’s noncontrolling interests.

In connection with the filing of a combined operating license application with the NRC for two new nuclear generation units, in January 2009, TCEH and Mitsubishi Heavy Industries Ltd. (MHI) formed a joint venture, known as Comanche Peak Nuclear Power Company LLC, to further the development of the two new nuclear generation units using MHI’s US–Advanced Pressurized Water Reactor technology. Under the terms of the joint venture agreement, a subsidiary of TCEH owns an 88% interest in the venture and a subsidiary of MHI owns a 12% interest. This joint venture is a variable interest entity, and a subsidiary of TCEH is considered the primary beneficiary under consolidations accounting standards.

Equity

The following table presents the changes to equity during the nine months ended September 30, 2009.


	EFH Corp. Shareholders’ Equity
	Common Stock (a)		Additional Paid-in Capital			Retained Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests (b)			Total Equity
Balance at December 31, 2008	$	—	$	8,045		$	(11,198	)	$	(379	)	$	1,355		$	(2,177	)
Net income		—		—			207			—			54			261
Effects of shareholder actions related to stated value of common stock		2		(2	)		—			—			—			—
Effects of EFH Corp. stock-based incentive compensation plans		—		12			—			—			—			12
Net effects of cash flow hedges		—		—			—			79			—			79
Distributions to noncontrolling interests		—		—			—			—			(32	)		(32	)
Investment by noncontrolling interests		—		—			—			—			42			42
Other		—		—			—			—			1			1

Balance at September 30, 2009	$	2	$	8,055		$	(10,991	)	$	(300	)	$	1,420		$	(1,814	)

(a)	Authorized shares totaled 2,000,000,000 ($0.001 stated value) as of September 30, 2009. Outstanding shares totaled 1,666,346,008 and 1,667,149,663 as of September 30, 2009 and December 31, 2008, respectively.

(b)	See Note 1 for discussion of adoption of amended guidance for accounting for noncontrolling interests in consolidated financial statements.

7.	COMMODITY AND OTHER DERIVATIVE CONTRACTUAL ASSETS AND LIABILITIES

Risk Management Hedging Strategy

We enter into physical and financial derivative instruments, such as options, swaps, futures and forward contracts, primarily to manage commodity price risk and interest rate risk exposure. Our principal activities involving derivatives consist of a long-term hedging program and the hedging of interest costs on our long-term debt. See Note 8 for a discussion of the fair value of all derivatives.

Long-Term Hedging Program — TCEH has a long-term hedging program designed to reduce exposure to changes in future electricity prices due to changes in the price of natural gas, thereby hedging future revenues from electricity sales and related cash flows. In ERCOT, the wholesale price of electricity is correlated to the price of natural gas. Under the program, TCEH has entered into market transactions involving natural gas-related financial instruments and has sold forward natural gas over the next five years. These transactions are intended to hedge a majority of electricity price exposure related to expected baseload generation for this period. Changes in the fair value of the instruments under the long-term hedging program are reported in the income statement in net gain (loss) from commodity hedging and trading activities.

Interest Rate Swap Transactions — Interest rate swap agreements are used to reduce exposure to interest rate changes by converting floating-rate debt to a fixed basis, thereby hedging future interest costs and related cash flows. Interest rate basis swaps are used to effectively reduce the hedged borrowing costs. Changes in the fair value of the swaps are recorded as unrealized gains and losses in interest expense and related charges. See Note 4 for additional information about these and other interest rate swap agreements.

Other Commodity Hedging and Trading Activity — In addition to the long-term hedging program, TCEH enters into derivatives, including electricity, natural gas, fuel oil and coal instruments, generally for shorter-term hedging purposes. To a limited extent, TCEH also enters into derivative transactions for proprietary trading purposes, principally in natural gas and electricity markets.

As of September 30, 2009, commodity positions accounted for as cash flow hedges, which represent a small portion of economic hedge positions, reduce exposure to variability of future cash flows through 2009.

The following table provides detail of commodity and other derivative contractual assets and liabilities as presented in the balance sheet at September 30, 2009:


	Derivatives not under hedge accounting											Cash flow hedges
	Derivative assets					Derivative liabilities						Derivative liabilities
	Commodity contracts			Interest rate swaps		Commodity contracts			Interest rate swaps			Commodity contracts			Total
Current assets	$	2,517		$	91	$	11		$	—		$	—		$	2,619
Noncurrent assets		1,118			5		30			—			—			1,153
Current liabilities		(28	)		—		(1,910	)		(709	)		(2	)		(2,649	)
Noncurrent liabilities		(19	)		—		(524	)		(800	)		—			(1,343	)

Net assets (liabilities)	$	3,588		$	96	$	(2,393	)	$	(1,509	)	$	(2	)	$	(220	)

Margin deposits that contractually offset these derivative instruments are reported separately in the balance sheet and totaled $396 million and $190 million in net liabilities at September 30, 2009 and December 31, 2008, respectively, which do not include the collateral investments related to certain interest rate swaps and commodity positions discussed immediately below. Amounts presented in the above table do not reflect netting of assets and liabilities with the same counterparties under existing netting arrangements. This presentation can result in significant volatility in derivative assets and liabilities because we may enter into offsetting positions with the same counterparties, resulting in both assets and liabilities, and the underlying commodity prices can change significantly from period to period.

In early 2009, we entered into collateral funding transactions with counterparties to certain interest rate swap agreements related to TCEH debt. Under the terms of these transactions, which we elected to enter into as a cash management measure, as of September 30, 2009 EFH Corp. (parent) has posted $400 million in cash and TCEH has posted $65 million in letters of credit to the counterparties, with the outstanding balance of such collateral earning interest. TCEH had also entered into commodity hedging transactions with one of these counterparties, and under an arrangement effective August 2009, both the interest rate swaps and certain of the commodity hedging transactions with the counterparty are under the same derivative agreement, which continues to be secured by a first-lien interest in the assets of TCEH. At September 30, 2009, the net mark-to-market liability under the derivative agreements exceeded the collateral posted under such agreements. In particular, the net commodity and interest rate swap mark-to-market liability related to the $400 million cash posting totaled $685 million at September 30, 2009. We are not required to post any additional collateral to these counterparties, regardless of the net mark-to-market liability under the applicable derivative agreement, and the applicable counterparty will return the cash collateral to the extent the mark-to-market liability under the applicable derivative agreement falls below the funded amount, subject to a $50 million minimum transfer amount. The counterparties are required to return any remaining collateral, along with accrued and unpaid interest, on March 31, 2010. The cash collateral was recorded as an investment and is presented in the balance sheet (including accrued interest) as a separate line item under current assets.

The following table presents the pre-tax effect of derivatives not under hedge accounting on net income, including realized and unrealized effects, for the three and nine months ended September 30, 2009:


Derivative (Income statement presentation)	Three Months Ended September 30, 2009			Nine Months Ended September 30, 2009

Commodity contracts (Net gain (loss) from commodity hedging and trading activities)	$	136		$	1,026

Interest rate swaps (Interest expense and related charges)		(317	)		16

Net gain (loss)	$	(181	)	$	1,042

Results for the three and nine months ended September 30, 2008 include net “day one” losses totaling $10 million and $68 million, respectively, primarily associated with commodity contracts entered into at below market prices. Substantially all of these amounts represent losses associated with related series of transactions involving natural gas financial instruments intended to hedge exposure to future changes in electricity prices. The losses are reported in the income statement in net gain (loss) from commodity hedging and trading activities, consistent with other mark-to-market hedging and trading gains and losses, and are included in the results of the Competitive Electric segment.

The following tables present the pre-tax effect of derivative instruments accounted for as cash flow hedges on net income (loss) and other comprehensive income (loss) (OCI) for the three and nine months ended September 30, 2009:


Three Months Ended September 30, 2009
Derivative	Amount of (loss) recognized in OCI (effective portion)			Income statement presentation of gain (loss) reclassified from accumulated OCI into income (effective portion)	Amount

Interest rate swaps	$	—		Interest expense and related charges	$	(56	)

Commodity contracts		(6	)	Fuel, purchased power costs and delivery fees		(6	)

				Operating revenues		—

Total	$	(6	)		$	(62	)


Nine Months Ended September 30, 2009
Derivative	Amount of (loss) recognized in OCI (effective portion)			Income statement presentation of gain (loss) reclassified from accumulated OCI into income (effective portion)	Amount

Interest rate swaps	$	—		Interest expense and related charges	$	(140	)

Commodity contracts		(31	)	Fuel, purchased power costs and delivery fees		(10	)

				Operating revenues		(2	)

Total	$	(31	)		$	(152	)

There were no ineffectiveness net gains or losses related to transactions currently designated as cash flow hedges in the three and nine months ended September 30, 2009.

Accumulated other comprehensive income related to cash flow hedges at September 30, 2009 totaled $159 million in net losses (after-tax), substantially all of which relates to interest rate swaps. We expect that $82 million of net losses related to cash flow hedges included in accumulated other comprehensive income as of September 30, 2009 will be reclassified into net income during the next twelve months as the related hedged transactions affect net income.

The following table presents the gross notional amounts of derivative volumes at September 30, 2009:


Derivative type	Notional Volume		Unit of Measure

Interest rate swaps:
Floating/fixed	$	19,250	Million US dollars
Basis	$	18,000	Million US dollars
Natural gas:
Long-term hedge forward sales and purchases (a)		3,522	Million MMBtu
Locational basis swaps		909	Million MMBtu
All other		1,366	Million MMBtu
Electricity		190,431	GWh
Coal		7	Million tons
Fuel oil		166	Million gallons

(a)

Represents gross notional forward sales, purchases and options of fixed and basis (price point) transactions in the long-term hedging program. The net amount of these transactions, excluding basis transactions, is 1.7 billion MMBtu.

Credit Risk-Related Contingent Features

The agreements that govern our derivative instrument transactions may contain certain credit risk-related contingent features that could trigger liquidity requirements in the form of cash collateral, letters of credit or some other form of credit enhancement. Certain of those agreements require the posting of collateral if our credit rating is downgraded by one or more of the credit rating agencies; however, due to our below investment grade ratings, substantially all of such collateral posting requirements are already effective.

As of September 30, 2009, the fair value of liabilities related to derivative instruments under agreements with credit risk-related contingent features that were not fully cash collateralized totaled $850 million. The liquidity exposure associated with these liabilities was reduced by cash and letter of credit postings with the counterparties totaling $162 million as of September 30, 2009. If all the credit risk-related contingent features related to these derivatives had been triggered, including cross default provisions, as of September 30, 2009, the remaining related liquidity requirement would have totaled $28 million after reduction for net accounts receivable and derivative assets under netting arrangements.

In addition, certain derivative agreements that are collateralized primarily with asset liens include indebtedness cross-default provisions that could result in the settlement of such contracts if there were a failure under other financing arrangements to meet payment terms or to comply with other covenants that could result in the acceleration of such indebtedness. As of September 30, 2009, the fair value of derivative liabilities subject to such cross-default provisions, largely related to interest rate swaps, totaled $1.716 billion (before consideration of the amount of assets under the liens). The liquidity exposure associated with these liabilities was reduced by cash collateral and letters of credit posted with counterparties totaling $483 million as of September 30, 2009. If all the credit risk-related contingent features related to these derivatives, including amounts related to cross-default provisions, had been triggered as of September 30, 2009, the remaining related liquidity requirement would have totaled $810 million after reduction for derivative assets under netting arrangements (before consideration of the amount of assets under the liens). See Note 15 to the Financial Statements in the 2008 Form 10-K for a description of other obligations that are supported by asset liens.

As discussed immediately above, the aggregate fair values of liabilities under derivative agreements with credit risk-related contingent features, including cross-default provisions, totaled $2.566 billion at September 30, 2009. This amount is before consideration of cash and letter of credit collateral posted, net accounts receivable and derivative assets under netting arrangements and assets under related liens.

Some commodity derivative contracts contain credit risk-related contingent features that do not provide for specific amounts to be posted if the features are triggered. These provisions include material adverse change, performance assurance, and other clauses that generally provide counterparties with the right to request additional credit enhancements. The amounts disclosed above exclude credit risk-related contingent features that do not provide for specific amounts or exposure calculations.

While the disclosures above address our derivative liabilities, we also manage our counterparty credit exposure with respect to derivative assets.

8.	FAIR VALUE MEASUREMENTS

Accounting standards related to the determination of fair value define fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. We use a “mid-market” valuation convention (the mid-point price between bid and ask prices) as a practical expedient to measure fair value for the majority of our assets and liabilities subject to fair value measurement on a recurring basis. We primarily use the market approach for recurring fair value measurements and use valuation techniques to maximize the use of observable inputs and minimize the use of unobservable inputs.

We categorize our assets and liabilities recorded at fair value based upon the following fair value hierarchy:

•

Level 1 valuations use quoted prices in active markets for identical assets or liabilities that are accessible at the measurement date. An active market is a market in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 assets and liabilities include exchange traded commodity contracts. For example, a significant number of our derivatives are NYMEX futures and swaps transacted through clearing brokers for which prices are actively quoted.

•

Level 2 valuations use inputs, in the absence of actively quoted market prices, that are observable for the asset or liability, either directly or indirectly. Level 2 inputs include: (a) quoted prices for similar assets or liabilities in active markets, (b) quoted prices for identical or similar assets or liabilities in markets that are not active, (c) inputs other than quoted prices that are observable for the asset or liability such as interest rates and yield curves observable at commonly quoted intervals and (d) inputs that are derived principally from or corroborated by observable market data by correlation or other means. Our Level 2 valuations utilize over-the-counter broker quotes, quoted prices for similar assets or liabilities that are corroborated by correlations or other mathematical means and other valuation inputs. For example, our Level 2 assets and liabilities include forward commodity positions at locations for which over-the-counter broker quotes are available.

•

Level 3 valuations use unobservable inputs for the asset or liability. Unobservable inputs are used to the extent observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. We use the most meaningful information available from the market combined with internally developed valuation methodologies to develop our best estimate of fair value. For example, our Level 3 assets and liabilities include certain derivatives whose values are derived from pricing models that utilize multiple inputs to the valuations, including inputs that are not observable or easily corroborated through other means.

We utilize several different valuation techniques to measure the fair value of assets and liabilities, relying primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities for those items that are measured on a recurring basis. These methods include, among others, the use of broker quotes and statistical relationships between different price curves.

In utilizing broker quotes, we attempt to obtain multiple quotes from brokers that are active in the commodity markets in which we participate (and require at least one quote from two brokers to determine a pricing input as observable); however, not all pricing inputs are quoted by brokers. The number of broker quotes received for certain pricing inputs varies depending on the depth of the trading market, each individual broker’s publication policy, recent trading volume trends and various other factors. In addition, for valuation of interest rate swaps, we use a combination of dealer provided market valuations (generally non-binding) and Bloomberg valuations based on month-end interest rate curves and standard rate swap valuation models.

Certain derivatives and financial instruments are valued utilizing option pricing models that take into consideration multiple inputs including commodity prices, volatility factors, discount rates and other inputs. Additionally, when there is not a sufficient amount of observable market data, valuation models are developed that incorporate proprietary views of market factors. Those valuation models are generally used in developing long-term forward price curves for certain commodities. We believe the development of such curves is consistent with industry practice; however, the fair value measurements resulting from such curves are classified as Level 3.

With respect to amounts presented in the following fair value hierarchy table, the fair value measurement of an asset or liability (e.g. a contract) is required to fall in its entirety in one level, based on the lowest level input that is significant to the fair value measurement. Certain assets and liabilities would be classified in Level 2 instead of Level 3 of the hierarchy except for the effects of credit reserves and non-performance risk adjustments, respectively. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability being measured.

At September 30, 2009, assets and liabilities measured at fair value on a recurring basis consisted of the following:


	Level 1		Level 2		Level 3 (a)		Reclassification (b)		Total
Assets:
Commodity contracts	$	1,035	$	2,276	$	277	$	88	$	3,676
Interest rate swaps		—		96		—		—		96
Nuclear decommissioning trust – equity securities (c)		142		99		—		—		241
Nuclear decommissioning trust – debt securities (c)		—		216		—		—		216

Total assets	$	1,177	$	2,687	$	277	$	88	$	4,229


Liabilities:
Commodity contracts	$	1,133	$	944	$	318	$	88	$	2,483
Interest rate swaps		—		1,509		—		—		1,509

Total liabilities	$	1,133	$	2,453	$	318	$	88	$	3,992

(a)	Level 3 assets and liabilities consist primarily of more complex long-term power purchase and sales agreements, including longer-term wind generation purchase contracts and certain natural gas positions (collars) in the long-term hedging program.

(b)	Represents the effects of reclassification of the assets and liabilities to conform to the balance sheet presentation of current and long-term assets and liabilities.

(c)	The nuclear decommissioning trust investment is included in the Investments line on the balance sheet. See Note 13.

At December 31, 2008, assets and liabilities measured at fair value on a recurring basis consisted of the following:


	Level 1		Level 2		Level 3 (a)		Total

Assets:
Commodity contracts	$	1,010	$	2,061	$	283	$	3,354
Interest rate swaps		—		142		—		142
Nuclear decommissioning trust – equity securities (b)		109		83		—		192
Nuclear decommissioning trust – debt securities (b)		—		193		—		193

Total assets	$	1,119	$	2,479	$	283	$	3,881


Liabilities:
Commodity contracts	$	1,288	$	1,274	$	355	$	2,917
Interest rate swaps		—		2,086		—		2,086

Total liabilities	$	1,288	$	3,360	$	355	$	5,003

(a)

Level 3 assets and liabilities consist primarily of more complex long-term power purchase and sales agreements, including longer-term wind generation purchase contracts and certain natural gas positions (collars) in the long-term hedging program.

(b)

The nuclear decommissioning trust investment is included in the Investments line on the balance sheet.

Commodity contracts consist primarily of natural gas, electricity, fuel oil and coal derivative instruments entered into for hedging purposes and include physical contracts that have not been designated “normal” purchases or sales. See Note 7 for further discussion regarding the company’s use of derivative instruments.

Interest rate swaps include variable-to-fixed rate swap instruments that are economic hedges of interest on long-term debt as well as interest rate basis swaps designed to effectively reduce the hedged borrowing costs. See Note 4 for discussion of interest rate swaps.

Nuclear decommissioning trust assets represent securities held for the purpose of funding the future retirement and decommissioning of the nuclear generation units. These investments include equity, debt and other fixed-income securities consistent with investment rules established by the NRC and the PUCT.

The following table presents the changes in fair value of the Level 3 assets and liabilities (all related to commodity contracts) for the three and nine months ended September 30, 2009 and 2008:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
Balance at beginning of period	$	(72	)	$	(539	)	$	(72	)	$	(173	)
Total realized and unrealized gains (losses) (a):
Included in net income (loss)		42			297			57			(48	)
Included in other comprehensive income (loss)		(6	)		(12	)		(31	)		3
Purchases, sales, issuances and settlements (net) (b)		(6	)		(42	)		(15	)		(45	)
Net transfers in and/or out of Level 3 (c)		1			104			20			71

Balance at end of period	$	(41	)	$	(192	)	$	(41	)	$	(192	)

Net change in unrealized gains (losses) included in net income relating to instruments held at end of period (d)	$	44		$	213		$	61		$	(33	)

(a)	Substantially all changes in values of commodity contracts are reported in the income statement in net gain (loss) from commodity hedging and trading activities.

(b)	Settlements represent reversals of unrealized mark-to-market valuations of these positions previously recognized in net income. Purchases and issuances reflect option premiums paid or received.

(c)

Includes transfers due to changes in the observability of significant inputs used in valuing derivatives. Transfers in are assumed to transfer in at the beginning of the quarter and transfers out at the end of the quarter, which is when the assessments are performed. Any changes in value during the period are reported as unrealized gains and losses in net gain (loss) from commodity hedging and trading activities.

(d)	Includes unrealized gains and losses of instruments held at the end of the period only related to the periods in which the instrument was classified as a Level 3 asset or liability.

9.	FAIR VALUE OF NONDERIVATIVE FINANCIAL INSTRUMENTS

The carrying amounts and related estimated fair values of significant nonderivative financial instruments were as follows:


	September 30, 2009						December 31, 2008
	Carrying Amount			Fair Value (a)			Carrying Amount			Fair Value (a)
On balance sheet assets (liabilities):
Long-term debt (including current maturities) (b):
TCEH, EFH Corp., and other	$	(36,473	)	$	(27,627	)	$	(35,860	)	$	(24,162	)
Oncor	$	(5,137	)	$	(5,862	)	$	(5,204	)	$	(4,990	)

Total	$	(41,610	)	$	(33,489	)	$	(41,064	)	$	(29,152	)

Off balance sheet assets (liabilities):
Financial guarantees	$	—		$	(8	)	$	—		$	(3	)

(a)	Fair value determined in accordance with accounting standards related to the determination of fair value.

(b)	Excludes capital leases.

See Notes 7 and 8 for discussion of accounting for financial instruments that are derivatives.

10.

PENSION AND OTHER POSTRETIREMENT EMPLOYEE BENEFITS (OPEB) COSTS

Net pension and OPEB costs for the three and nine months ended September 30, 2009 and 2008 are comprised of the following:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
Components of net pension costs:
Service cost	$	10		$	12		$	28		$	29
Interest cost		40			51			119			117
Expected return on assets		(41	)		(56	)		(124	)		(133	)
Prior service cost		—			—			—			1
Net loss		4			—			7			—

Net pension costs		13			7			30			14

Components of net OPEB costs:
Service cost		3			3			8			8
Interest cost		15			14			46			44
Expected return on assets		(3	)		(5	)		(10	)		(15	)
Prior service cost		—			—			—			(1	)
Net loss		3			2			9			8

Net OPEB costs		18			14			53			44


Net pension and OPEB costs		31			21			83			58
Less amounts deferred principally as a regulatory asset or property		(18	)		(10	)		(51	)		(32	)

Net amounts recognized as expense	$	13		$	11		$	32		$	26

The discount rates reflected in net pension and OPEB costs in 2009 are 6.90% and 6.85%, respectively. The expected rates of return on pension and OPEB plan assets reflected in the 2009 cost amounts are 8.25% and 7.64%, respectively.

We made cash contributions related to our pension and OPEB plans of $61 million and $16 million, respectively, in the first nine months of 2009, and we expect to make additional contributions of $18 million and $6 million, respectively, in the remainder of 2009.

11.

RELATED PARTY TRANSACTIONS

We incur an annual management fee under terms of a management agreement with the Sponsor Group for which we accrued $9 million for both the three months ended September 30, 2009 and 2008, and $27 million and $26 million for the nine months ended September 30, 2009 and 2008, respectively. The fee is reported as SG&A expense in Corporate and Other activities.

At the closing of the Merger, TCEH entered into the TCEH Senior Secured Facilities and Oncor entered into a revolving credit facility, each with syndicates of financial institutions and other lenders. These syndicates included affiliates of GS Capital Partners, which is a member of the Sponsor Group. Affiliates of GS Capital Partners and Kohlberg Kravis Roberts & Co. L.P. (a member of the Sponsor Group) have from time to time engaged in commercial banking and financial advisory transactions with us in the normal course of business.

Affiliates of the Sponsor Group are participating in exchange offers announced in October 2009 by EFH Corp., Intermediate Holding and EFIH Finance to exchange new senior secured notes for the EFH Corp. Securities and the TCEH Cash-Pay Notes. Goldman, Sachs & Co. and KKR Capital Markets LLC are acting as dealer managers and TPG Capital, L.P. is serving as an advisor in the exchange offers. (See Note 4 for additional information). These affiliates will be compensated for their services in accordance with the terms of the exchange offer agreements.

Affiliates of Goldman Sachs & Co. are parties to certain commodity and interest rate hedging transactions with us in the normal course of business.

Affiliates of the Sponsor Group may sell or acquire debt or debt securities issued by us in open market transactions or through loan syndications.

12.

SEGMENT INFORMATION

Our operations are aligned into two reportable business segments: Competitive Electric and Regulated Delivery. The segments are managed separately because they are strategic business units that offer different products or services and involve different risks.

The Competitive Electric segment is engaged in competitive market activities consisting of electricity generation, the development and construction of new generation facilities, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity sales to residential and business customers, all largely in Texas. These activities are conducted by TCEH. The results of this segment also include equipment salvage and resale activities related to the 2007 cancellation of the development of eight new coal-fueled generation units; such activities were not material for the periods presented.

The Regulated Delivery segment is engaged in regulated electricity transmission and distribution operations in Texas. These activities are conducted by Oncor, including its wholly-owned bankruptcy-remote financing subsidiary.

Corporate and Other represents the remaining nonsegment operations consisting primarily of general corporate expenses and interest on EFH Corp. (parent entity) and EFC Holdings debt.

The accounting policies of the business segments are the same as those described in the summary of significant accounting policies in Note 1 above and in Note 1 in the 2008 Form 10-K. We evaluate performance based on income from continuing operations. We record intersegment sales and transfers as if the sales or transfers were to third parties, that is, at current market prices.


	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
Operating revenues:
Competitive Electric	$	2,433		$	3,258		$	6,144		$	7,809
Regulated Delivery		770			728			2,037			1,969
Corporate and Other		3			10			16			27
Eliminations		(321	)		(301	)		(831	)		(804	)

Consolidated	$	2,885		$	3,695		$	7,366		$	9,001


Affiliated revenues included in operating revenues:
Competitive Electric	$	2		$	2		$	5		$	5
Regulated Delivery		316			290			813			775
Corporate and Other		3			9			13			24
Eliminations		(321	)		(301	)		(831	)		(804	)

Consolidated	$	—		$	—		$	—		$	—


Net income (loss):
Competitive Electric	$	(44	)	$	3,611		$	436		$	(862	)
Regulated Delivery		132			139			272			309
Corporate and Other		(142	)		(133	)		(447	)		(430	)

Consolidated	$	(54	)	$	3,617		$	261		$	(983	)

13.

SUPPLEMENTARY FINANCIAL INFORMATION

Regulated Versus Unregulated Operations


	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
Operating revenues
Regulated	$	770		$	728		$	2,037		$	1,969
Unregulated		2,436			3,268			6,160			7,836
Intercompany sales eliminations – regulated		(316	)		(290	)		(813	)		(775	)
Intercompany sales eliminations – unregulated		(5	)		(11	)		(18	)		(29	)

Total operating revenues		2,885			3,695			7,366			9,001

Fuel, purchased power and delivery fees – unregulated (a)		(870	)		(1,631	)		(2,171	)		(3,867	)
Net gain (loss) from commodity hedging and trading activities – unregulated		123			6,045			1,003			(248	)
Operating costs – regulated		(228	)		(213	)		(668	)		(620	)
Operating costs – unregulated		(160	)		(157	)		(503	)		(500	)
Depreciation and amortization – regulated		(147	)		(128	)		(405	)		(370	)
Depreciation and amortization – unregulated		(309	)		(303	)		(881	)		(847	)
Selling, general and administrative expenses – regulated		(50	)		(42	)		(139	)		(126	)
Selling, general and administrative expenses – unregulated		(227	)		(207	)		(653	)		(586	)
Franchise and revenue-based taxes – regulated		(67	)		(67	)		(185	)		(186	)
Franchise and revenue-based taxes – unregulated		(27	)		(25	)		(74	)		(73	)
Impairment of goodwill		—			—			(90	)		—
Other income		45			14			71			43
Other deductions		(32	)		(541	)		(50	)		(583	)
Interest income		18			9			30			22
Interest expense and other charges		(1,039	)		(831	)		(2,136	)		(2,505	)

Income (loss) before income taxes	$	(85	)	$	5,618		$	515		$	(1,445	)

(a)

Includes unregulated cost of fuel consumed of $360 million and $538 million for the three months ended September 30, 2009 and 2008, respectively, and $943 million and $1.320 billion for the nine months ended September 30, 2009 and 2008, respectively. The balance represents energy purchased for resale and delivery fees net of intercompany eliminations.

Other Income and Deductions


	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
Other income:
Accretion of adjustment (discount) of regulatory assets resulting from purchase accounting	$	10	$	11	$	30	$	33
Reversal of reserve recorded in purchase accounting (a)		23		—		23		—
Fee received related to interest rate swap/commodity hedge derivative agreement (b) (Note 7)		6		—		6		—
Mineral rights royalty income		1		1		3		3
Other		5		2		9		7

Total other income	$	45	$	14	$	71	$	43

Other deductions:
Impairment of emission allowances intangible assets	$	—	$	499	$	—	$	501
Charge related to Lehman bankruptcy (c)		—		26		—		26
Write-off of regulatory assets (Note 13)		25		—		25		—
Transition and business optimization costs		—		8		—		8
Net charges related to cancelled development of generation facilities		1		2		3		10
Severance charges		—		—		6		—
Professional fees incurred related to the Merger		—		1		—		4
Costs related to 2006 cities rate settlement		1		—		2		13
Litigation/regulatory settlements		—		—		—		6
Other		5		5		14		15

Total other deductions	$	32	$	541	$	50	$	583

(a)	Reversal of a use tax accrual, related to periods prior to the Merger, due to state ruling in the third quarter of 2009. (Reported in Competitive Electric segment.)

(b)	Reported in Competitive Electric segment.

(c)	Reserve established against amounts due (excluding termination related costs) from subsidiaries of Lehman Brothers Holdings Inc. arising from commodity hedging and trading activities. (Reported in Competitive Electric segment.)

Interest Expense and Related Charges


	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
Interest (including net amounts settled/ accrued under interest rate swaps)	$	874		$	860		$	2,619		$	2,583
Unrealized mark-to-market net (gain) loss on interest rate swaps		138			(36	)		(527	)		(36	)
Amortization of interest rate swap losses at dedesignation of hedge accounting		56			17			140			17
Amortization of fair value debt discounts resulting from purchase accounting		17			18			56			55
Amortization of debt issuance costs and discounts		34			48			104			111
Capitalized interest, primarily related to generation facility and regulated utility asset construction		(80	)		(76	)		(256	)		(225	)

Total interest expense and related charges	$	1,039		$	831		$	2,136		$	2,505

Restricted Cash


	At September 30, 2009				At December 31, 2008
	Current Assets		Noncurrent Assets		Current Assets		Noncurrent Assets
Amounts related to the TCEH Letter of Credit Facility (See Note 4)	$	—	$	1,135	$	—	$	1,250
Amounts related to margin deposits held		—		—		4		—
Amounts related to securitization (transition) bonds		64		15		51		17

Total restricted cash	$	64	$	1,150	$	55	$	1,267

Inventories by Major Category


	September 30, 2009		December 31, 2008
Materials and supplies	$	234	$	199
Fuel stock		222		162
Natural gas in storage		28		65

Total inventories	$	484	$	426

Investments


	September 30, 2009		December 31, 2008
Nuclear decommissioning trust	$	457	$	385
Assets related to employee benefit plans, including employee savings programs, net of distributions		208		210
Land		44		44
Investment in natural gas gathering pipeline business (a)		31		—
Miscellaneous other		4		6

Total investments	$	744	$	645

(a)

A controlling interest in this previously consolidated subsidiary was sold in August 2009.

Nuclear Decommissioning Trust — Investments in a trust that will be used to fund the costs to decommission the Comanche Peak nuclear generation plant are carried at fair value. Decommissioning costs are being recovered from Oncor’s customers as a delivery fee surcharge over the life of the plant and deposited in the trust fund. Net gains and losses on investments in the trust fund are offset by a corresponding adjustment to a regulatory asset/liability. A summary of investments in the fund follows:


	September 30, 2009
	Cost (a)		Unrealized gain		Unrealized loss			Fair market value
Debt securities (b)	$	210	$	9	$	(3	)	$	216
Equity securities (c)		191		71		(21	)		241

Total	$	401	$	80	$	(24	)	$	457


	December 31, 2008
	Cost (a)		Unrealized gain		Unrealized loss			Fair market value
Debt securities (b)	$	203	$	4	$	(14	)	$	193
Equity securities (c)		181		46		(35	)		192

Total	$	384	$	50	$	(49	)	$	385

(a)	Includes realized gains and losses of securities sold.

(b)

The investment objective for debt securities is to invest in a diversified tax efficient portfolio with an overall portfolio rating of AA or above as graded by S&P or Aa2 by Moody’s. The debt securities are heavily weighted with municipal bonds. The debt securities had an average coupon rate of 4.15% and 3.77% and an average maturity of 8.3 years and 8.0 years at September 30, 2009 and December 31, 2008, respectively.

(c)	The investment objective for equity securities is to invest tax efficiently and to match the performance of the S&P 500 Index.

Debt securities held at September 30, 2009 mature as follows: $79 million in one to five years, $33 million in five to ten years and $104 million after ten years.

Property, Plant and Equipment

As of September 30, 2009 and December 31, 2008, property, plant and equipment of $30.0 billion and $29.5 billion, respectively, is stated net of accumulated depreciation and amortization of $6.7 billion and $5.6 billion, respectively.

Asset Retirement Obligations

These liabilities primarily relate to nuclear generation plant decommissioning, land reclamation related to lignite mining, removal of lignite/coal-fueled plant ash treatment facilities and generation plant asbestos removal and disposal costs. There is no earnings impact with respect to the recognition of the asset retirement costs for nuclear decommissioning, as all costs are recoverable through the regulatory process as part of Oncor’s rates.

The following table summarizes the changes to the asset retirement liability, reported in other noncurrent liabilities and deferred credits in the balance sheet, during the nine months ended September 30, 2009:


Asset retirement liability at January 1, 2009	$	859
Additions:
Accretion		45
Reductions:
Payments, essentially all mining reclamation		(21	)

Asset retirement liability at September 30, 2009	$	883

Oncor’s Regulatory Assets and Liabilities

Recognition of regulatory assets and liabilities and the amortization periods over which they are expected to be recovered or refunded through rate regulation reflect the decisions of the PUCT. Components of the regulatory assets and liabilities are provided in the table below; amounts not earning a return through rate regulation are noted. On August 31, 2009, the PUCT issued a final order on Oncor’s rate review filed in June 2008. The rate review included a determination of the recoverability of regulatory assets as of December 31, 2007, including the recoverability period of those assets deemed allowable by the PUCT. The PUCT’s findings included denial of recovery of certain regulatory assets, primarily related to business restructuring costs and rate case expenses, which resulted in a $25 million charge ($16 million after-tax) in the third quarter 2009 reported in other deductions in the Regulated Delivery segment.


	Remaining Rate Recovery/Amortization Period as of September 30, 2009	Carrying Amount
		September 30, 2009		December 31, 2008
Regulatory assets:
Generation-related regulatory assets securitized by transition bonds (a)	7 years	$	787	$	865
Employee retirement costs	5 years		84		—
Employee retirement costs to be reviewed (b)(c)	To be determined		37		100
Employee retirement liability (a)(c)(d)	To be determined		542		559
Self-insurance reserve (primarily storm recovery costs) – net	7 years		142		—
Self-insurance reserve to be reviewed (b)(c)	To be determined		109		214
Nuclear decommissioning cost under-recovery (a)(c)(e)	Not applicable		90		127
Securities reacquisition costs (pre-industry restructure)	8 years		63		68
Securities reacquisition costs (post-industry restructure)	Terms of related debt		28		29
Recoverable amounts for/in lieu of deferred income taxes – net	Life of related asset or liability		76		77
Rate case expenses (f)	Largely 3 years		9		10
Rate case expenses to be reviewed (b)(c)	To be determined		2		—
Advanced meter customer education costs	10 years		4		2
Deferred conventional meter depreciation	10 years		2		—
Business restructuring costs (g)	Not applicable		—		20

Total regulatory assets			1,975		2,071


Regulatory liabilities:
Committed spending for demand-side management initiatives (a)	3 years		87		96
Deferred advanced metering system revenues	10 years		51		—
Investment tax credit and protected excess deferred taxes	Various		46		49
Over-collection of securitization (transition) bond revenues (a)	7 years		32		28
Other regulatory liabilities (a)	Various		4		6

Total regulatory liabilities			220		179


Net regulatory asset		$	1,755	$	1,892

(a)	Not earning a return in the regulatory rate-setting process.

(b)	Costs incurred since the period covered under the last rate review.

(c)	Recovery is specifically authorized by statute, subject to reasonableness review by the PUCT.

(d)	Represents unfunded liabilities recorded in accordance with pension and OPEB accounting standards.

(e)	Offset by an intercompany payable to TCEH.

(f)	Rate case expenses totaling $4 million were disallowed by the PUCT and written off in the third quarter of 2009.

(g)	All previously recorded business restructuring costs were disallowed by the PUCT and written off in the third quarter of 2009.

As part of purchase accounting, the carrying value of the generation-related regulatory assets was reduced by $213 million, and this amount is being accreted to other income over the approximate nine-year recovery period remaining as of the date of the Merger.

In September 2008, the PUCT approved a settlement for Oncor to recover its estimated future investment for advanced metering deployment. Oncor began billing the advanced metering surcharge in the January 2009 billing month cycle. The surcharge is expected to total $1.023 billion over the 11-year recovery period and includes a cost recovery factor of $2.19 per month per residential retail customer and $2.39 to $5.15 per month for non-residential retail customers. We account for the difference between the surcharge billings for advanced metering facilities and the allowed revenues under the surcharge provisions, which are based on expenditures and an allowed return, as a regulatory asset or liability; such differences arise principally as a result of timing of expenditures. As indicated in the table above, the regulatory liability at September 30, 2009 totaled $51 million.

Exit Liabilities

As part of purchase accounting for the Merger, we accrued $54 million in costs expected to be incurred related to the termination and transition of outsourcing arrangements. We incurred $7 million and $17 million of the exit liabilities in the three and nine months ended September 30, 2009, respectively, and the remaining accrual is expected to be settled no later than June 30, 2010, the targeted date of completion of transition of outsourced activities back to us or to service providers.

Other Noncurrent Liabilities and Deferred Credits

The balance of other noncurrent liabilities and deferred credits consists of the following:


	September 30, 2009		December 31, 2008
Uncertain tax positions (including accrued interest)	$	1,924	$	1,780
Retirement plan and other employee benefits		1,446		1,451
Asset retirement obligations		883		859
Unfavorable purchase and sales contracts		707		727
Liabilities related to subsidiary tax sharing agreement		314		299
Other		101		89

Total other noncurrent liabilities and deferred credits	$	5,375	$	5,205

We do not expect the total amount of liabilities recorded related to uncertain tax positions to significantly increase or decrease within the next 12 months. As of September 30, 2009, the federal income tax benefit on the interest accrued on uncertain tax positions is recorded as accumulated deferred income taxes.

Unfavorable Purchase and Sales Contracts — The amortization of unfavorable purchase and sales contracts totaled $7 million and $6 million in the three months ended September 30, 2009 and 2008, respectively, and $21 million and $23 million in the nine months ended September 30, 2009 and 2008, respectively. Favorable purchase and sales contracts are recorded as intangible assets (see Note 2).

The estimated amortization of unfavorable purchase and sales contracts for each of the five succeeding fiscal years from December 31, 2008 is as follows:


Year	Amount
2009	$	27
2010		27
2011		27
2012		27
2013		26

Liabilities Related to Subsidiary Tax Sharing Agreement — Amount represents the noncontrolling interests’ portion of the previously recorded net deferred tax liabilities of Oncor. Upon the sale of noncontrolling interests in Oncor (see Note 6), Oncor became a partnership for US federal income tax purposes, and the temporary differences which gave rise to the deferred taxes will, over time, become taxable to the noncontrolling interests. Under a tax sharing agreement among Oncor and its equity holders, Oncor reimburses its equity holders for federal income taxes as the partnership earnings become taxable to such holders. Accordingly, as the temporary differences become taxable, the equity holders will be reimbursed by Oncor. In the unlikely event such amounts are not reimbursed under the tax sharing agreement, it is probable they would be refunded to rate payers. The net changes in the liability for the nine months ended September 30, 2009 of $15 million reflected changes in temporary differences.

Supplemental Cash Flow Information


	Nine Months Ended September 30,
	2009			2008
Cash payments (receipts) related to:
Interest paid (a)	$	2,042		$	2,262
Capitalized interest		(256	)		(225	)

Interest paid (net of capitalized interest) (a)		1,786			2,307
Income taxes		(38	)		(61	)
Noncash investing and financing activities:
Issuance of toggle notes in lieu of cash interest for EFH Corp. and TCEH		248			—
Noncash construction expenditures (b)		132			180
Capital leases		15			13

(a)

Net of interest received on interest rate swaps.

(b)

Represents end-of-period accruals.

14.

SUPPLEMENTAL GUARANTOR CONDENSED FINANCIAL INFORMATION

In 2007, EFH Corp. issued $2.0 billion 10.875% Senior Notes Due 2017 and $2.5 billion 11.25%/12.00% Senior Toggle Notes Due 2017 (collectively, the EFH Corp. Senior Notes). In May 2009, EFH Corp. issued an additional $150 million of the EFH Corp. Toggle Notes (see Note 4). The EFH Corp. Senior Notes are unconditionally guaranteed by EFC Holdings and Intermediate Holding, 100% owned subsidiaries of EFH Corp. (collectively, the Guarantors) on an unsecured basis. The guarantees issued by the Guarantors are full and unconditional, joint and several guarantees of the EFH Corp. Senior Notes. The guarantees rank equally with any senior unsecured indebtedness of the Guarantors and rank effectively junior to all of the secured indebtedness of the Guarantors to the extent of the assets securing that indebtedness. All other subsidiaries of EFH Corp., either direct or indirect, do not guarantee the EFH Corp. Senior Notes (collectively, the Non-Guarantors). The indenture governing the EFH Corp. Senior Notes contains certain restrictions, subject to certain exceptions, on EFH Corp.’s ability to pay dividends or make investments. See Note 6.

The following tables have been prepared in accordance with Regulation S-X Rule 3-10, “Financial Statements of Guarantors and Issuers of Guaranteed Securities Registered or Being Registered” in order to present the condensed consolidating statements of income of EFH Corp. (the Parent/Issuer), the Guarantors and the Non-Guarantors for the three-month and nine-month periods ended September 30, 2009 and 2008, the condensed consolidating statements of cash flows of the Parent/Issuer, the Guarantors and the Non-Guarantors for the nine-month periods ended September 30, 2009 and 2008 and the condensed consolidating balance sheets as of September 30, 2009 and December 31, 2008 of the Parent/Issuer, the Guarantors and the Non-Guarantors. Investments in consolidated subsidiaries are accounted for under the equity method. The presentations reflect the application of SEC Staff Accounting Bulletin Topic 5-J, Push Down Basis of Accounting Required in Certain Limited Circumstances, including the effects of the push down of the $4.65 billion and $4.5 billion EFH Corp. Senior Notes to the Guarantors as of September 30, 2009 and December 31, 2008, respectively (see Notes 4 and 5).

EFH Corp. (Parent) received dividends from its consolidated subsidiaries totaling $117 million and $213 million for the nine months ended September 30, 2009 and 2008, respectively.

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Income (Loss)

For the Three Months Ended September 30, 2009

(millions of dollars)


	Parent/ Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	2,885		$	—		$	2,885
Fuel, purchased power costs and delivery fees		—			—			(870	)		—			(870	)
Net gain from commodity hedging and trading activities		—			—			123			—			123
Operating costs		—			—			(388	)		—			(388	)
Depreciation and amortization		—			—			(456	)		—			(456	)
Selling, general and administrative expenses		(29	)		—			(248	)		—			(277	)
Franchise and revenue-based taxes		—			—			(94	)		—			(94	)
Other income		—			—			45			—			45
Other deductions		—			—			(32	)		—			(32	)
Interest income		62			—			46			(90	)		18
Interest expense and related charges		(250	)		(142	)		(876	)		229			(1,039	)


Income (loss) before income taxes and equity earnings of subsidiaries		(217	)		(142	)		135			139			(85	)

Income tax (expense) benefit		75			48			(46	)		(46	)		31

Equity earnings of subsidiaries		62			81			—			(143	)		—


Net income (loss)		(80	)		(13	)		89			(50	)		(54	)

Net income attributable to noncontrolling interests		—			—			(26	)		—			(26	)


Net income (loss) attributable to EFH Corp.	$	(80	)	$	(13	)	$	63		$	(50	)	$	(80	)

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Income (Loss)

For the Three Months Ended September 30, 2008

(millions of dollars)


	Parent/ Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	3,695		$	—		$	3,695
Fuel, purchased power costs and delivery fees		—			—			(1,631	)		—			(1,631	)
Net gain from commodity hedging and trading activities		—			—			6,045			—			6,045
Operating costs		—			—			(372	)		2			(370	)
Depreciation and amortization		—			—			(431	)		—			(431	)
Selling, general and administrative expenses		(29	)		—			(219	)		(1	)		(249	)
Franchise and revenue-based taxes		—			—			(92	)		—			(92	)
Other income		—			—			14			—			14
Other deductions		(9	)		—			(532	)		—			(541	)
Interest income		43			—			44			(78	)		9
Interest expense and related charges		(229	)		(131	)		(677	)		206			(831	)


Income (loss) before income taxes and equity earnings of subsidiaries		(224	)		(131	)		5,844			129			5,618

Income tax (expense) benefit		87			45			(2,088	)		(45	)		(2,001	)

Equity earnings of subsidiaries		3,754			3,768			—			(7,522	)		—


Net income (loss)	$	3,617		$	3,682		$	3,756		$	(7,438	)	$	3,617

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Income (Loss)

For the Nine Months Ended September 30, 2009

(millions of dollars)


	Parent/ Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	7,366		$	—		$	7,366
Fuel, purchased power costs and delivery fees		—			—			(2,171	)		—			(2,171	)
Net gain from commodity hedging and trading activities		—			—			1,003			—			1,003
Operating costs		—			—			(1,171	)		—			(1,171	)
Depreciation and amortization		—			—			(1,286	)		—			(1,286	)
Selling, general and administrative expenses		(92	)		—			(700	)		—			(792	)
Franchise and revenue-based taxes		—			(1	)		(258	)		—			(259	)
Impairment of goodwill		—			—			(90	)		—			(90	)
Other income		2			—			69			—			71
Other deductions		(3	)		—			(47	)		—			(50	)
Interest income		173			—			103			(246	)		30
Interest expense and related charges		(727	)		(423	)		(1,647	)		661			(2,136	)


Income (loss) before income taxes and equity earnings of subsidiaries		(647	)		(424	)		1,171			415			515

Income tax (expense) benefit		213			141			(468	)		(140	)		(254	)

Equity earnings of subsidiaries		641			710			—			(1,351	)		—


Net income		207			427			703			(1,076	)		261

Net income attributable to noncontrolling interests		—			—			(54	)		—			(54	)


Net income attributable to EFH Corp.	$	207		$	427		$	649		$	(1,076	)	$	207

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Income (Loss)

For the Nine Months Ended September 30, 2008

(millions of dollars)


	Parent/ Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Operating revenues	$	—		$	—		$	9,001		$	—		$	9,001
Fuel, purchased power costs and delivery fees		—			—			(3,867	)		—			(3,867	)
Net loss from commodity hedging and trading activities		—			—			(248	)		—			(248	)
Operating costs		—			—			(1,120	)		—			(1,120	)
Depreciation and amortization		—			—			(1,217	)		—			(1,217	)
Selling, general and administrative expenses		(84	)		—			(628	)		—			(712	)
Franchise and revenue-based taxes		—			1			(260	)		—			(259	)
Other income		—			—			43			—			43
Other deductions		(17	)		—			(566	)		—			(583	)
Interest income		122			5			113			(218	)		22
Interest expense and related charges		(679	)		(401	)		(2,034	)		609			(2,505	)


Income (loss) before income taxes and equity earnings of subsidiaries		(658	)		(395	)		(783	)		391			(1,445	)

Income tax (expense) benefit		217			134			242			(131	)		462

Equity earnings of subsidiaries		(542	)		(502	)		—			1,044			—


Net income (loss)	$	(983	)	$	(763	)	$	(541	)	$	1,304		$	(983	)

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows

For the Nine Months Ended September 30, 2009

(millions of dollars)


	Parent/ Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Cash provided by (used in) operating activities	$	(43	)	$	113		$	1,907		$	(234	)	$	1,743


Cash flows – financing activities:
Issuances of long-term borrowings		—			—			522			—			522
Retirements of long-term borrowings		—			(3	)		(294	)		—			(297	)
Change in short-term borrowings		—			—			200			—			200
Contributions from noncontrolling interests		—			—			42			—			42
Distributions paid to noncontrolling interests		—			—			(32	)		—			(32	)
Cash dividends paid		—			(117	)		(117	)		234			—
Change in advances – affiliates		289			7			—			(296	)		—
Other, net		20			—			(35	)		—			(15	)

Cash provided by (used in) financing activities		309			(113	)		286			(62	)		420


Cash flows – investing activities:
Capital expenditures and nuclear fuel purchases		—			—			(2,004	)		—			(2,004	)
Money market fund redemptions		—			—			142			—			142
Investment posted with derivative counterparty		(400	)		—			—			—			(400	)
Net proceeds from sale of majority interest in natural gas gathering pipeline business		—			—			40			—			40
Reduction of restricted cash related to letter of credit facility		—			—			115			—			115
Proceeds from sale of environmental allowances and credits		—			—			22			—			22
Purchases of environmental allowances and credits		—			—			(23	)		—			(23	)
Proceeds from sales of nuclear decommissioning trust fund securities		—			—			2,972			—			2,972
Investments in nuclear decommissioning trust fund securities		—			—			(2,983	)		—			(2,983	)
Change in advances – affiliates		—			—			(296	)		296			—
Other, net		—			—			(8	)		—			(8	)

Cash provided by (used in) investing activities		(400	)		—			(2,023	)		296			(2,127	)


Net change in cash and cash equivalents		(134	)		—			170			—			36
Cash and cash equivalents – beginning balance		1,075			—			614			—			1,689

Cash and cash equivalents – ending balance	$	941		$	—		$	784		$	—		$	1,725

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows

For the Nine Months Ended September 30, 2008

(millions of dollars)


	Parent/ Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Cash provided by (used in) operating activities	$	(136	)	$	292		$	1,227		$	(426	)	$	957


Cash flows – financing activities:
Issuances of securities:
Long-term debt		—			—			2,777			—			2,777
Common stock		34			—			—			—			34
Retirements/repurchases of securities:
Long-term debt		(200	)		(2	)		(472	)		—			(674	)
Common stock		(1	)		—			—			—			(1	)
Change in short-term borrowings		—			—			902			—			902
Cash dividends paid		—			(213	)		(213	)		426			—
Change in advances – affiliates		269			—			—			(269	)		—
Other, net		—			—			14			—			14

Cash provided by (used in) financing activities		102			(215	)		3,008			157			3,052


Cash flows – investing activities:
Capital expenditures and nuclear fuel purchases		—			—			(2,179	)		—			(2,179	)
Investments held in money market fund		—			—			(242	)		—			(242	)
Proceeds from sale of environmental allowances and credits		—			—			30			—			30
Purchases of environmental allowances and credits		—			—			(18	)		—			(18	)
Proceeds from sales of nuclear decommissioning trust fund securities		—			—			747			—			747
Investments in nuclear decommissioning trust fund securities		—			—			(758	)		—			(758	)
Change in advances – affiliates		—			(77	)		(192	)		269			—
Other, net		2			—			44			—			46

Cash provided by (used in) investing activities		2			(77	)		(2,568	)		269			(2,374	)


Net change in cash and cash equivalents		(32	)		—			1,667			—			1,635
Cash and cash equivalents – beginning balance		32			—			249			—			281

Cash and cash equivalents – ending balance	$	—		$	—		$	1,916		$	—		$	1,916

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Balance Sheets

at September 30, 2009

(millions of dollars)


	Parent/ Issuer			Guarantors			Non-Guarantors		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	941		$	—		$	784	$	—		$	1,725
Investment posted with counterparty		417			—			—		—			417
Restricted cash		—			—			64		—			64
Advances to affiliates		413			4			—		(417	)		—
Trade accounts receivable – net		9			—			1,005		—			1,014
Income taxes receivable		180			5			—		(185	)		—
Accounts receivable from affiliates		—			—			12		(12	)		—
Notes receivable from affiliates		112			—			1,166		(1,278	)		—
Inventories		—			—			484		—			484
Commodity and other derivative contractual assets		82			—			2,537		—			2,619
Accumulated deferred income taxes		7			1			93		—			101
Margin deposits related to commodity positions		—			—			158		—			158
Other current assets		3			—			142		—			145

Total current assets		2,164			10			6,445		(1,892	)		6,727

Restricted cash		—			—			1,150		—			1,150
Investments		4,510			3,469			677		(7,912	)		744
Property, plant and equipment – net		—			—			30,019		—			30,019
Notes receivable from affiliates		13			—			2,245		(2,258	)		—
Goodwill		—			—			14,316		—			14,316
Intangible assets – net		—			—			2,907		—			2,907
Regulatory assets – net		—			—			1,755		—			1,755
Commodity and other derivative contractual assets		—			—			1,153		—			1,153
Accumulated deferred income taxes		478			57			—		(535	)		—
Unamortized debt issuance costs and other noncurrent assets		111			95			769		(95	)		880

Total assets	$	7,276		$	3,631		$	61,436	$	(12,692	)	$	59,651


LIABILITIES AND EQUITY
Current liabilities:
Short-term borrowings	$	—		$	—		$	1,437	$	—		$	1,437
Advances from affiliates		—			—			417		(417	)		—
Long-term debt due currently		4			7			315		—			326
Trade accounts payable		7			—			731		—			738
Accounts payable to affiliates		7			5			—		(12	)		—
Notes payable to affiliates		1,112			18			148		(1,278	)		—
Commodity and other derivative contractual liabilities		114			—			2,535		—			2,649
Margin deposits related to commodity positions		—			—			504		—			504
Accumulated deferred income taxes		—			—			—		—			—
Accrued interest		291			225			563		(223	)		856
Other current liabilities		9			1			869		(185	)		694

Total current liabilities		1,544			256			7,519		(2,115	)		7,204

Accumulated deferred income taxes		—			—			6,546		(483	)		6,063
Investment tax credits		—			—			38		—			38
Commodity and other derivative contractual liabilities		—			—			1,343		—			1,343
Notes or other liabilities due affiliates		2,019			—			239		(2,258	)		—
Long-term debt, less amounts due currently		6,531			4,746			34,815		(4,650	)		41,442
Other noncurrent liabilities and deferred credits		416			3			4,956		—			5,375

Total liabilities		10,510			5,005			55,456		(9,506	)		61,465

EFH Corp. shareholders’ equity		(3,234	)		(1,374	)		4,560		(3,186	)		(3,234	)
Noncontrolling interests in subsidiaries		—			—			1,420		—			1,420

Total equity		(3,234	)		(1,374	)		5,980		(3,186	)		(1,814	)

Total liabilities and equity	$	7,276		$	3,631		$	61,436	$	(12,692	)	$	59,651

ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES

Condensed Consolidating Balance Sheets

at December 31, 2008

(millions of dollars)


	Parent/ Issuer			Guarantors			Non-Guarantors		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	1,075		$	—		$	614	$	—		$	1,689
Investments held in money market fund		—			—			142		—			142
Restricted cash		—			—			55		—			55
Advances to affiliates		403			7			—		(410	)		—
Trade accounts receivable – net		3			—			1,216		—			1,219
Income taxes receivable		—			—			128		(86	)		42
Accounts receivable from affiliates		—			—			3		(3	)		—
Notes receivable from affiliates		—			—			633		(633	)		—
Inventories		—			—			426		—			426
Commodity and other derivative contractual assets		143			—			2,391		—			2,534
Accumulated deferred income taxes		—			—			80		(36	)		44
Margin deposits related to commodity positions		—			—			439		—			439
Other current assets		6			—			159		—			165

Total current assets		1,630			7			6,286		(1,168	)		6,755

Restricted cash		—			—			1,267		—			1,267
Investments		3,899			2,793			579		(6,626	)		645
Property, plant and equipment – net		—			—			29,522		—			29,522
Notes receivable from affiliates		12			—			2,273		(2,285	)		—
Goodwill		—			—			14,386		—			14,386
Intangible assets – net		—			—			2,993		—			2,993
Regulatory assets – net		—			—			1,892		—			1,892
Commodity and other derivative contractual assets		—			—			962		—			962
Accumulated deferred income taxes		575			6			—		(581	)		—
Unamortized debt issuance costs and other noncurrent assets		130			111			711		(111	)		841

Total assets	$	6,246		$	2,917		$	60,871	$	(10,771	)	$	59,263


LIABILITIES AND EQUITY
Current liabilities:
Short-term borrowings	$	—		$	—		$	1,237	$	—		$	1,237
Advances from affiliates		—			—			410		(410	)		—
Long-term debt due currently		3			8			374		—			385
Trade accounts payable		8			—			1,135		—			1,143
Accounts payable to affiliates		—			3			—		(3	)		—
Notes payable to affiliates		585			13			35		(633	)		—
Commodity and other derivative contractual liabilities		178			—			2,730		—			2,908
Margin deposits related to commodity positions		—			—			525		—			525
Accumulated deferred income taxes		36			—			—		(36	)		—
Accrued interest		110			87			413		(86	)		524
Other current liabilities		111			—			587		(86	)		612

Total current liabilities		1,031			111			7,446		(1,254	)		7,334

Accumulated deferred income taxes		—			—			6,507		(581	)		5,926
Investment tax credits		—			—			42		—			42
Commodity and other derivative contractual liabilities		—			—			2,095		—			2,095
Notes or other liabilities due affiliates		2,019			—			266		(2,285	)		—
Long-term debt, less amounts due currently		6,340			4,597			34,401		(4,500	)		40,838
Other noncurrent liabilities and deferred credits		388			1			4,817		(1	)		5,205

Total liabilities		9,778			4,709			55,574		(8,621	)		61,440

EFH Corp. shareholders’ equity		(3,532	)		(1,792	)		3,942		(2,150	)		(3,532	)
Noncontrolling interests in subsidiaries		—			—			1,355		—			1,355

Total equity		(3,532	)		(1,792	)		5,297		(2,150	)		(2,177	)

Total liabilities and equity	$	6,246		$	2,917		$	60,871	$	(10,771	)	$	59,263

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of Energy Future Holdings Corp.:

We have reviewed the accompanying condensed consolidated balance sheet of Energy Future Holdings Corp. and subsidiaries (“EFH Corp.”) as of September 30, 2009, and the related condensed statements of consolidated income (loss) and comprehensive income (loss) for the three-month and nine-month periods ended September 30, 2009 and 2008, and of cash flows for the nine-month periods ended September 30, 2009 and 2008. These interim financial statements are the responsibility of EFH Corp.’s management.

We conducted our reviews in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our reviews, we are not aware of any material modifications that should be made to such condensed consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Energy Future Holdings Corp. and subsidiaries as of December 31, 2008, and the related statements of consolidated income (loss), comprehensive income (loss), cash flows, and shareholders’ equity for the year then ended (not presented herein); and in our report dated March 2, 2009 (May 20, 2009 as to the effects of the retrospective adoption of new accounting guidance related to noncontrolling interests in consolidated financial statements) (which report includes an explanatory paragraph related to EFH Corp. completing its merger with Texas Energy Future Merger Sub Corp and becoming a subsidiary of Texas Energy Future Holdings Limited Partnership on October 10, 2007, EFH Corp.’s adoption of new accounting guidance related to noncontrolling interests in consolidated financial statements, the provisions of accounting guidance related to the presentation of assets and liabilities with the legal right of offset and reclassification of results of its commodity hedging and trading activities on a retrospective basis), we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2008 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ Deloitte & Touche LLP

Dallas, Texas

October 29, 2009

Item 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations for the three and nine months ended September 30, 2009 and 2008 should be read in conjunction with our consolidated financial statements and the notes to those statements.

All dollar amounts in the tables in the following discussion and analysis are stated in millions of US dollars unless otherwise indicated.

BUSINESS

We are a Dallas-based holding company conducting operations principally through our TCEH and Oncor subsidiaries. TCEH is a holding company for subsidiaries engaged in competitive electricity market activities largely in Texas including electricity generation, development and construction of new generation facilities, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity sales. Oncor is a majority-owned (approximately 80%) subsidiary engaged in regulated electricity transmission and distribution operations in Texas. Various “ring-fencing” measures have been taken to further separate Oncor from our other businesses. See Note 1 to Financial Statements for a description of the material features of these “ring-fencing” measures and Note 6 to Financial Statements for discussion of noncontrolling interests sold by Oncor.

Operating Segments

We have aligned and report our business activities as two operating segments: the Competitive Electric segment and the Regulated Delivery segment. The Competitive Electric segment is principally comprised of TCEH. The segment also includes equipment salvage and resale activities related to the cancellation of the development of eight new coal-fueled generation units in 2007; such activities were not material for the periods presented in this Quarterly Report. The Regulated Delivery segment is comprised of Oncor and its wholly-owned bankruptcy-remote financing subsidiary.

See Note 12 to Financial Statements for further information regarding reportable business segments.

Significant Activities and Events

Long-Term Hedging Program — TCEH has a long-term hedging program designed to reduce exposure to changes in future electricity prices due to changes in the price of natural gas. Under the program, the company has entered into market transactions involving natural gas-related financial instruments, and as of September 30, 2009, has effectively sold forward approximately 1.7 billion MMBtu of natural gas (equivalent to the natural gas exposure of approximately 214,000 GWh at an assumed 8.0 market heat rate) for the period from October 1, 2009 through December 31, 2014 at weighted average annual hedge prices ranging from $7.19 per MMBtu to $8.05 per MMBtu. These transactions, as well as forward power sales, have effectively hedged an estimated 71% of the natural gas price exposure related to TCEH’s expected generation output for the period beginning October 1, 2009 and ending December 31, 2014 (on an average basis for such period and assuming an 8.0 market heat rate). The hedges were entered into with the continuing expectation that wholesale electricity prices in ERCOT will be highly correlated with natural gas prices, which are expected to be the marginal fuel for the purpose of setting electricity prices approximately 75% to 90% of the time. If the correlation changes in the future, the cash flows targeted under the long-term hedging program may not be achieved.

The long-term hedging program is comprised primarily of contracts with prices based on the NYMEX Henry Hub pricing point. However, because there are other local and regional natural gas pricing points such as Houston Ship Channel, future wholesale power prices in ERCOT may not correlate as closely to the Henry Hub pricing as other pricing points, which could decrease the effectiveness of the positions in the long-term hedging program in mitigating power price exposure. The company has hedged more than 95% of the Houston Ship Channel versus Henry Hub pricing point risk for the fourth quarter 2009 period and more than 95% for 2010.

The company has entered into related put and call transactions (referred to as collars), primarily for year 2014 of the program, that effectively hedge natural gas prices within a range. These transactions represented approximately 6% of the positions in the long-term hedging program at September 30, 2009, with the approximate weighted average strike prices under the collars being a floor of $7.80 per MMBtu and a ceiling of $11.75 per MMBtu. Financial instruments, including collars, are expected to be employed in future hedging activity under the long-term hedging program.

The following table summarizes the natural gas hedges in the long-term hedging program as of September 30, 2009:

Measure

Balance
2009 (a)

2010

2011

2012

2013

2014

Total

Natural gas hedge volumes (b)

mm MMBtu

~58

~298

~466

~492

~300

~97

~1,711

Weighted average hedge price (c)

$/MMBtu

~8.05

~7.80

~7.56

~7.36

~7.19

~7.80

—

Weighted average market price (d)

$/MMBtu

~4.75

~6.21

~6.87

~7.00

~7.06

~7.17

—

(a)	Balance of 2009 is from October 1, 2009 through December 31, 2009

(b)	Where collars are reflected, the volumes are estimated based on the natural gas price sensitivity (i.e. delta position) of the derivatives. The notional volumes for collars are approximately 150 million MMBtu, which corresponds to a delta position of approximately 97 million MMBtu in 2014.

(c)

Weighted average hedge prices are based on sales prices of forward natural gas sales positions in the long-term hedging program based on NYMEX Henry Hub prices (excluding the impact of offsetting purchases for rebalancing and pricing point basis transactions). Where collars are reflected, sales price represents the collar floor price.

(d)	Based on NYMEX Henry Hub prices.

Changes in the fair value of the instruments in the long-term hedging program are being recorded as unrealized gains and losses in net gain (loss) from commodity hedging and trading activities in the statement of income, which has and could continue to result in significant volatility in reported net income. Based on the size of the long-term hedging program as of September 30, 2009, a $1.00/MMBtu change in natural gas prices across the hedged period would result in the recognition of up to approximately $1.7 billion in pretax unrealized mark-to-market gains or losses.

The reported unrealized mark-to-market net loss related to the long-term hedging program for the three months ended September 30, 2009 totaled $106 million. This amount reflects a $145 million net gain due to the effect of lower forward prices of natural gas on the value of positions in the program, which was more than offset by net losses of $251 million representing reversals of previously recorded unrealized gains on positions that settled in the period. The reported unrealized net gain for the nine months ended September 30, 2009 totaled $559 million. This amount reflects a $1.086 billion net gain due to the effect of lower forward prices of natural gas on the value of positions in the program, partially offset by net losses of $527 million representing reversals of previously recorded net gains on positions that settled in the period. Given the volatility of natural gas prices, it is not possible to predict future reported unrealized mark-to-market gains or losses and the actual gains or losses that will ultimately be realized upon settlement of the hedge positions in future years. If natural gas prices at settlement are lower than the prices of the hedge positions, the hedges are expected to mitigate the otherwise negative effect on earnings of lower wholesale electricity prices. However, if natural gas prices at settlement are higher than the prices of the hedge positions, the hedges are expected to dampen the otherwise positive effect on earnings of higher wholesale electricity prices and will in this context be viewed as having resulted in an opportunity cost. The cumulative unrealized mark-to-market net gain related to positions in the long-term hedging program totaled $1.430 billion and $871 million at September 30, 2009 and December 31, 2008, respectively. These values can change materially as market conditions change.

As of September 30, 2009, more than 95% of the long-term hedging program transactions were directly or indirectly secured by a first-lien interest in TCEH’s assets (including the transactions supported by the TCEH Commodity Collateral Posting Facility – see discussion below under “Liquidity and Capital Resources”) thereby reducing the cash and letter of credit collateral requirements for the hedging program.

The following sensitivity table provides estimates of the potential impact (in $millions) of movements in natural gas and certain other commodity prices and market heat rates on realized pre-tax earnings for the periods presented. The estimates related to price sensitivity are based on TCEH’s unhedged position and forward prices as of September 30, 2009, which for natural gas reflects estimates of electricity generation less amounts hedged through the long-term natural gas hedging program and amounts under existing wholesale and retail sales contracts. On a rolling twelve-month basis, the substantial majority of retail sales under month-to-month arrangements are deemed to be under contract.

Balance 2009 (a)

2010

2011

2012

2013

$1.00/MMBtu change in gas price (b)

~12

~41

~91

~279

0.1/MMBtu/MWh change in market heat rate (c)

—

~16

~49

~57

~59

$1.00/gallon change in diesel fuel price

—

~50

$10.00/pound change in uranium/nuclear fuel

—

(a)	Balance of 2009 is from November 1, 2009 through December 31, 2009.

(b)	Assumes conversion of electricity positions based on an approximate 8.0 market heat rate with natural gas being on the margin 75% to 90% of the time (i.e. when coal is forecast to be on the margin, no natural gas position is assumed to be generated).

(c)	Based on Houston Ship Channel natural gas prices as of September 30, 2009.

Debt Exchange Offers and Consent Solicitations — See Note 4 to Financial Statements for discussion of debt exchange offers and consent solicitations commenced in October 2009.

TCEH Interest Rate Swap Transactions — As of September 30, 2009, TCEH had entered into a series of interest rate swaps that effectively fix the interest rates at between 7.3% and 8.3% on $17.55 billion principal amount of its senior secured debt maturing from 2009 to 2014. All of these swaps were entered into prior to January 1, 2009. Taking into consideration these swap transactions, approximately 7% of our total long-term debt portfolio at September 30, 2009 was exposed to variable interest rate risk. TCEH also entered into interest rate basis swap transactions, which further reduce fixed borrowing costs, related to an aggregate of $18.0 billion principal amount of senior secured debt, including swaps entered into in 2009 related to $9.55 billion principal amount of debt and reflecting the expiration in 2009 of swaps related to an aggregate $4.595 billion principal amount of debt. We may enter into additional interest rate hedges from time to time. Unrealized mark-to-market net gains and losses related to all TCEH interest rate swaps, which are reported in interest expense and related charges, totaled $138 million in net losses and $527 million in net gains for the three and nine month periods ended September 30, 2009, respectively. The cumulative unrealized mark-to-market net liability related to all TCEH interest rate swaps totaled $1.4 billion at September 30, 2009, of which $238 million (pre-tax) was reported in accumulated other comprehensive income. These fair values can change materially as market conditions change, which could result in significant volatility in reported net income. See discussion in Note 4 to Financial Statements regarding various interest rate swap transactions.

Texas Generation Facilities Development — TCEH is developing three lignite-fueled generation units (2 units at Oak Grove and 1 unit at Sandow) in the state of Texas with a total estimated capacity of approximately 2,200 MW. The Sandow unit achieved substantial completion (as defined in the EPC Agreement for the unit) effective September 30, 2009. Accordingly, the company has operational control of the unit. The first Oak Grove unit, which is in the commissioning and start-up phase, synchronized to the grid in August 2009 and is expected to achieve substantial completion (as defined in the EPC Agreement) in the fourth quarter of 2009. The second Oak Grove unit is nearing completion of construction and initiation of the commissioning and start-up phase and is expected to achieve substantial completion (as defined in the EPC Agreement) in mid-2010. Aggregate cash capital expenditures for these three units are expected to total approximately $3.25 billion including all construction, site preparation and mining development costs, of which approximately $3.1 billion was spent as of September 30, 2009. Total recorded costs, including purchase accounting fair value adjustments and capitalized interest, are expected to total approximately $4.8 billion upon completion of the units, and the balance was $4.6 billion as of September 30, 2009. See discussion in Note 5 to Financial Statements regarding contingencies related to the units.

Nuclear Generation Development — In September 2008, TCEH filed a combined operating license application with the NRC for two new nuclear generation units, each with approximately 1,700 MW (gross) capacity, at its existing Comanche Peak nuclear generation site. In connection with the filing of the application, in January 2009, TCEH and Mitsubishi Heavy Industries Ltd. (MHI) formed a joint venture to further the development of the two new nuclear generation units using MHI’s US–Advanced Pressurized Water Reactor technology. A subsidiary of TCEH owns an 88% interest in the joint venture, and a subsidiary of MHI owns a 12% interest.

In March 2009, the NRC announced an official review schedule for the license application. Based on the schedule, the NRC expects to complete its review by December 2011, and it is expected that a license would be issued approximately one year later.

While TCEH was not one of the initial four applicants selected to receive DOE loan guarantees, it continues to update its DOE loan guarantee application for financing the proposed units.

Idling of Natural Gas-Fueled Units — In February 2009, we notified ERCOT of plans to retire 11 of our natural gas-fueled units, totaling 2,229 MW of capacity (2,341 MW installed nameplate capacity), in May 2009, and mothball (idle) an additional four units, totaling 1,596 MW of capacity (1,675 MW of installed nameplate capacity), in September 2009. In May and September 2009, we entered into reliability-must-run (RMR) agreements for the remainder of 2009 with ERCOT for the operation of one unit originally planned to be retired with 115 MW of capacity (115 MW of installed nameplate capacity) and one unit planned to be mothballed with 515 MW of capacity (540 MW of installed nameplate capacity), respectively. The other units were retired in May 2009 or mothballed in September 2009 as originally planned. An impairment charge of $229 million related to the carrying value of these units was recorded in the fourth quarter of 2008.

Global Climate Change — A number of pieces of legislation dealing with greenhouse gas (GHG) emissions have been proposed recently in the US Congress, including the Waxman-Markey bill, known as the American Clean Energy and Security Act of 2009 (Waxman-Markey) and the Kerry-Boxer bill, known as the Clean Energy Jobs and American Power Act (Kerry-Boxer). This proposed legislation is not law, but in June 2009, Waxman-Markey was passed by the US House of Representatives and sent to the US Senate for consideration. Kerry-Boxer is currently being debated in the US Senate Environment and Public Works Committee. President Obama has also expressed support for Waxman-Markey and Kerry-Boxer.

As currently proposed, Waxman-Markey takes several approaches to address GHG emissions, including establishing renewable energy and energy efficiency standards, establishing performance standards for coal-fueled electricity generation units, and creating an economy-wide cap-and-trade program. The renewable energy and energy efficiency standards would require retail electricity suppliers to meet 6% of their load with renewable energy sources by 2012, increasing to 20% of their load by 2020, some of which could be met by energy efficiency measures. The performance standards for coal-fueled electricity generation units would require a 65% reduction in CO₂ emissions for subject generation units initially permitted after January 1, 2020, and a 50% reduction in CO₂ emissions for subject electricity generation units initially permitted between January 1, 2009 and January 1, 2020 once certain technology deployment criteria are met but no later than January 1, 2025. The cap-and-trade program would require emissions from capped sources, including coal-fueled electricity generation units, to be reduced 3% below 2005 levels by 2012, 17% by 2020, 42% by 2030 and 83% by 2050. The version of Waxman-Markey passed by the US House of Representatives included provisions that allocated a large percentage of the emissions allowances at no charge to various groups that would be impacted by such a cap-and-trade program, including certain merchant coal-fueled generation units. The Kerry-Boxer proposal employs a cap and trade approach similar to Waxman-Markey. However, there are the following key differences between Waxman-Markey and Kerry-Boxer: (i) a 20% reduction in CO₂ emissions levels by 2020; (ii) a smaller grant of emission allowances to the electric power sector, including merchant coal-fueled generation units and (iii) the lack of renewable energy and energy efficiency standards that are addressed in a separate proposal in the US Senate.

Both Waxman-Markey and Kerry-Boxer remain subject to deliberation and modifications in the US Congress, thereby precluding an accurate estimate of the cost of compliance; however, if Waxman-Markey, Kerry-Boxer or similar legislation were to be adopted, our costs of compliance with the law could be material.

In April 2007, the US Supreme Court issued a decision in the case of Massachusetts v. US Environmental Protection Agency holding that CO₂ and other GHG emissions are pollutants subject to regulation under the new motor vehicle provisions of the federal Clean Air Act. The case was remanded to the EPA for further rulemaking to determine whether GHG emissions may reasonably be anticipated to endanger public health or welfare, or in the alternative, provide a reasonable explanation why GHG emissions should not be regulated. In April 2009, the EPA issued a proposed determination finding that six GHGs in the atmosphere were pollutants under the Clean Air Act, the combination of the six GHGs formed air pollution, that this air pollution, through the mechanics of climate change, endangers public health and welfare, and that the emission of four of these GHGs by motor vehicles contributes to this air pollution and thereby the threat of climate change. Although this “endangerment finding” is in draft form and applies only to GHG emissions from motor vehicle engines, some of the GHGs that are the subject of the proposed endangerment finding are produced by the combustion of fossil fuels by other sources as well, including fossil-fueled electricity generation units. The public comment period for the proposed endangerment finding ended in June 2009. The EPA must now decide whether to issue a final endangerment finding, and whether it will proceed with the rulemaking process to promulgate regulations related to the finding. If such regulations are adopted, costs of compliance with such regulations could be material. The EPA continues to take steps to regulate GHG emissions, as represented by its recent proposal to establish permitting requirements for substantial new sources of GHGs.

In September 2009, the US Court of Appeals for the Second Circuit issued a decision in the case of State of Connecticut v. American Electric Power Company Inc. holding that various states, a municipality and certain private trusts have standing to sue and have sufficiently alleged a cause of action under the federal common law of nuisance for injuries allegedly caused by the defendant power generation companies’ emissions of GHGs. While the decision does not address the merits of the nuisance claim, and is still subject to appeal, it might encourage or form the basis for other lawsuits asserting similar nuisance claims regarding emissions of GHGs.

In October 2009, the US Court of Appeals for the Fifth Circuit also issued a decision in the case of Comer v. Murphy Oil USA holding that certain Mississippi residents have standing to sue to pursue state law nuisance, negligence and trespass claims for injuries purportedly suffered because the defendants’ emissions of GHGs allegedly increased the destructive force of Hurricane Katrina. This decision, like the American Electric Power decision discussed above, does not address the merits of such a nuisance claim and is still subject to appeal.

While we are not a party to these suits, if any similar suit was successfully asserted against us in the future, it could have a material adverse effect on our business, results of operations and financial condition.

Oncor Technology Initiatives — Oncor continues to invest in technology initiatives that include development of a modernized grid through the replacement of existing meters with advanced digital metering equipment and development of advanced digital communication, data management, real-time monitoring and outage detection capabilities. This modernized grid is expected to produce electricity service reliability improvements and provide the potential for additional products and services from REPs that will enable businesses and consumers to better manage their electricity usage and costs. Oncor’s plans provide for the full deployment of over three million advanced meters by the end of 2012 to all residential and most non-residential retail electricity customers in Oncor’s service area. As of September 30, 2009, Oncor has installed approximately 310 thousand advanced digital meters, including approximately 270 thousand in the nine months ended September 30, 2009. Cumulative capital expenditures for the deployment of the advanced meter system totaled $137 million as of September 30, 2009. In July 2009, Oncor’s advanced metering system completed its first 15-minute interval, billing-quality electricity consumption data reporting to the Texas market. The data, which makes it possible to support innovative new programs and pricing options, represented information technology integration of over 200,000 advanced meters.

In July 2009, Oncor applied to the US Department of Energy for approximately $317 million in stimulus funds to advance its modernized grid initiatives. In October 2009, the US Department of Energy notified Oncor that these applications were not selected for funding.

Oncor Matters with the PUCT — See discussion of these matters, including the awarded construction of $1.3 billion of transmission lines and a rate case with the PUCT, below under “Regulation and Rates.”

RESULTS OF OPERATIONS

Consolidated Financial Results — Three Months Ended September 30, 2009 Compared to Three Months Ended September 30, 2008

Reference is made to the comparisons of results by business segment that follow the discussion of consolidated results. The business segment comparisons provide additional detail and quantification of items affecting financial results.

Operating revenues decreased $810 million, or 22%, to $2.885 billion in 2009.

•

Operating revenues in the Competitive Electric segment decreased $825 million, or 25%, to $2.433 billion.

•

Operating revenues in the Regulated Delivery segment increased $42 million, or 6%, to $770 million.

•

Net intercompany sales eliminations increased $27 million reflecting higher sales by Oncor to REP subsidiaries of TCEH.

Fuel, purchased power costs and delivery fees decreased $761 million, or 47%, to $870 million in 2009. See discussion below in the analysis of Competitive Electric segment results of operations.

Net gains from commodity hedging and trading activities totaled $123 million in 2009 compared to $6.045 billion in 2008. Results in 2009 included unrealized mark-to-market net gains totaling $20 million. See discussion below in the analysis of Competitive Electric segment results of operations.

Operating costs increased $18 million, or 5%, to $388 million in 2009.

•

Operating costs in the Competitive Electric segment increased $3 million, or 2%, to $161 million.

•

Operating costs in the Regulated Delivery segment increased $15 million, or 7%, to $228 million.

Depreciation and amortization increased $25 million, or 6%, to $456 million in 2009.

•

Depreciation and amortization in the Competitive Electric segment increased $7 million, or 2%, to $303 million.

•

Depreciation and amortization in the Regulated Delivery segment increased $19 million, or 15%, to $147 million.

SG&A expenses increased $28 million, or 11%, to $277 million in 2009.

•

SG&A expenses in the Competitive Electric segment increased $20 million, or 12%, to $192 million.

•

SG&A expenses in the Regulated Delivery segment increased $8 million, or 19%, to $50 million.

•

Corporate and Other SG&A expenses totaled $35 million in both periods as higher transition costs associated with outsourced support services were offset by lower stock-based compensation expense and lower program fees related to the sale of accounts receivable.

Other income totaled $45 million in 2009 and $14 million in 2008. The 2009 amount included $23 million arising from the reversal of a use tax accrual recorded in purchase accounting related to periods prior to the Merger, which was triggered by a state ruling in the third quarter of 2009. The 2009 and 2008 amounts also included $10 million and $11 million, respectively, in accretion of the fair value adjustment to certain regulatory assets due to purchase accounting. Other deductions totaled $32 million in 2009 and $541 million in 2008. The 2009 amount includes a $25 million write off of regulatory assets as discussed in Note 13 to Financial Statements under “Oncor’s Regulatory Assets and Liabilities.” The 2008 amount included $499 million in impairment charges related to NOx and SO₂ environmental allowances intangible assets and $26 million in charges to reserve for net receivables (excluding termination related costs) from terminated hedging transactions with subsidiaries of Lehman Brothers Holdings Inc., which filed for bankruptcy under Chapter 11 of the US Bankruptcy Code. See Note 13 to Financial Statements for details of other income and deductions.

Interest expense and related charges increased $208 million to $1.039 billion in 2009 reflecting a $138 million unrealized mark-to-market net loss in 2009 related to interest rate swaps compared to a net gain of $36 million in 2008 and $39 million in increased noncash amortization of losses on interest rate swaps dedesignated as cash flow hedges in August 2008. See Note 13 to Financial Statements.

Income tax benefit totaled $31 million in 2009 compared to income tax expense of $2.001 billion in 2008. The effective rate on a loss in 2009 was 36.5%, and the effective rate on income in 2008 was 35.6%. The increase in the rate was driven by the impact of non-taxable earnings on certain employee benefit plan investments and higher lignite depletion deduction, partially offset by the impact of interest accrued for uncertain tax positions.

Earnings decreased $3.671 billion to a net loss of $54 million in 2009.

•

Earnings in the Competitive Electric segment decreased $3.655 billion to a net loss of $44 million.

•

Earnings in the Regulated Delivery segment decreased $7 million to $132 million.

Corporate and Other net expenses totaled $142 million in 2009 and $133 million in 2008. The amounts in 2009 and 2008 include recurring interest expense on outstanding debt and notes payable to subsidiaries, as well as corporate general and administrative expenses. The increase of $9 million reflects a lower effective tax rate on a loss reflecting an increase in interest accrued for uncertain tax positions.

Consolidated Financial Results — Nine Months Ended September 30, 2009 Compared to Nine Months Ended September 30, 2008

Operating revenues decreased $1.635 billion, or 18%, to $7.366 billion in 2009.

•

Operating revenues in the Competitive Electric segment decreased $1.665 billion, or 21%, to $6.144 billion.

•

Operating revenues in the Regulated Delivery segment increased $68 million, or 3%, to $2.037 billion.

•

Net intercompany sales eliminations increased $38 million, reflecting higher sales by Oncor to REP subsidiaries of TCEH.

Fuel, purchased power costs and delivery fees decreased $1.696 billion, or 44%, to $2.171 billion in 2009. See discussion below in the analysis of Competitive Electric segment results of operations.

Results from commodity hedging and trading activities totaled $1.003 billion in net gains in 2009 compared to $248 million in net losses in 2008. Results in 2009 included unrealized mark-to-market net gains totaling $769 million driven by the effect of lower forward market prices of natural gas on the value of positions in the long-term hedging program. See discussion below in the analysis of Competitive Electric segment results of operations.

Operating costs increased $51 million, or 5%, to $1.171 billion in 2009.

•

Operating costs in the Competitive Electric segment increased $4 million, or 1%, to $504 million.

•

Operating costs in the Regulated Delivery segment increased $48 million, or 8%, to $668 million.

Depreciation and amortization increased $69 million, or 6%, to $1.286 billion in 2009.

•

Depreciation and amortization in the Competitive Electric segment increased $35 million, or 4%, to $862 million.

•

Depreciation and amortization in the Regulated Delivery segment increased $35 million, or 9%, to $405 million.

SG&A expenses increased $80 million, or 11%, to $792 million in 2009.

•

SG&A expenses in the Competitive Electric segment increased $56 million, or 11%, to $555 million.

•

SG&A expenses in the Regulated Delivery segment increased $13 million, or 10%, to $139 million.

•

Corporate and Other SG&A expenses increased $11 million, or 13%, to $98 million as $29 million in higher transition costs associated with outsourced support services were partially offset by lower stock-based compensation expense and lower program fees related to the sale of accounts receivable.

See Note 2 to Financial Statements for discussion of the $90 million additional impairment of goodwill in 2009.

Other income totaled $71 million in 2009 and $43 million in 2008, including $30 million and $33 million, respectively, in accretion of the fair value adjustment to certain regulatory assets due to purchase accounting and a $23 million reversal of a use tax accrual in 2009, as described in the third quarter analysis above. Other deductions totaled $50 million in 2009 and $583 million in 2008. The 2009 amount includes a $25 million write off of regulatory assets as discussed in Note 13 to Financial Statements under “Oncor’s Regulatory Assets and Liabilities.” The 2008 amount includes $501 million in impairment charges related to NOx and SO₂ environmental allowances intangible assets and $26 million in charges to reserve for net receivables (excluding termination related costs) from terminated hedging transactions with subsidiaries of Lehman Brothers Holdings Inc., which filed for bankruptcy under Chapter 11 of the US Bankruptcy Code. See Note 13 to Financial Statements for details of other income and deductions.

Interest expense and related charges decreased $369 million to $2.136 billion in 2009 reflecting $491 million in higher unrealized mark-to-market net gains related to interest rate swaps, which was partially offset by $123 million in increased noncash amortization of losses on interest rate swaps dedesignated as cash flow hedges. Increased interest expense of $24 million due to higher average borrowings and $9 million due to higher average interest rates was largely offset by a $31 million increase in capitalized interest. See Note 13 to Financial Statements.

Income tax expense totaled $254 million in 2009 compared to an income tax benefit of $462 million in 2008. The effective rate on income in 2009 was 49.3%, and the effective rate on a loss in 2008 was 32.0%. The increase in the rate reflects the non-deductible goodwill impairment in 2009, which increased the effective rate by 7 percentage points. In addition, interest accrued on uncertain tax positions increased the rate on income in 2009 and decreased the rate on a loss in 2008.

Earnings increased $1.244 billion to $261 million in net income in 2009.

•

Earnings in the Competitive Electric segment increased $1.298 billion to $436 million.

•

Earnings in the Regulated Delivery segment decreased $37 million to $272 million.

•

Corporate and Other net expenses totaled $447 million in 2009 and $430 million in 2008. The amounts in 2009 and 2008 include recurring interest expense on outstanding debt and notes payable to subsidiaries, as well as corporate general and administrative expenses. The increase of $17 million reflected a $20 million goodwill impairment and the $7 million increase in SG&A expense as discussed above, partially offset by $11 million in interest income related to a $400 million collateral funding arrangement (see Note 7 to Financial Statements).

Competitive Electric Segment

Financial Results


	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008

Operating revenues	$	2,433		$	3,258		$	6,144		$	7,809
Fuel, purchased power costs and delivery fees		(1,187	)		(1,923	)		(2,987	)		(4,646	)
Net gain (loss) from commodity hedging and trading activities		123			6,045			1,003			(248	)
Operating costs		(161	)		(158	)		(504	)		(500	)
Depreciation and amortization		(303	)		(296	)		(862	)		(827	)
Selling, general and administrative expenses		(192	)		(172	)		(555	)		(499	)
Franchise and revenue-based taxes		(27	)		(26	)		(74	)		(74	)
Impairment of goodwill		—			—			(70	)		—
Other income		33			2			38			8
Other deductions		(7	)		(533	)		(22	)		(559	)
Interest income		21			20			40			46
Interest expense and related charges		(798	)		(605	)		(1,414	)		(1,824	)


Income (loss) before income taxes		(65	)		5,612			737			(1,314	)

Income tax (expense) benefit		21			(2,001	)		(301	)		452


Net income (loss)	$	(44	)	$	3,611		$	436		$	(862	)

Competitive Electric Segment

Sales Volume and Customer Count Data


	Three Months Ended September 30,				% Change		Nine Months Ended September 30,				% Change
	2009		2008		% Change		2009		2008		% Change
Sales volumes:

Retail electricity sales volumes – (GWh):
Residential	9,348		9,098		2.7		22,312		22,153		0.7
Small business (a)	2,598		2,241		15.9		6,228		5,802		7.3
Large business and other customers	4,049		4,038		0.3		10,905		10,951		(0.4	)

Total retail electricity	15,995		15,377		4.0		39,445		38,906		1.4
Wholesale electricity sales volumes	10,126		12,472		(18.8	)	30,180		35,529		(15.1	)
Net sales (purchases) of balancing electricity to/from ERCOT	(38	)	145		—		(304	)	(1,335	)	(77.2	)

Total sales volumes	26,083		27,994		(6.8	)	69,321		73,100		(5.2	)


Average volume (kWh) per residential customer (b):	4,936		4,802		2.8		11,772		11,767		—

Weather (North Texas average) – percent of normal (c):

Cooling degree days	99.1	%	100.7	%	(1.6	)	103.3	%	109.0	%	(5.2	)
Heating degree days	—	%	—	%	—		89.3	%	93.7	%	(4.7	)

Customer counts:

Retail electricity customers (end of period and in thousands) (d):
Residential							1,876		1,909		(1.7	)
Small business (a)							273		276		(1.1	)
Large business and other customers							23		27		(14.8	)

Total retail electricity customers							2,172		2,212		(1.8	)

(a)	Customers with demand of less than 1 MW annually.

(b)	Calculated using average number of customers for the period.

(c)

Weather data is obtained from Weatherbank, Inc., an independent company that collects and archives weather data from reporting stations of the National Oceanic and Atmospheric Administration (a federal agency under the US Department of Commerce). Normal is defined as the average over a 20-year period.

(d)

Based on number of meters. Typically, large business and other customers have more than one meter; therefore, number of meters does not reflect the number of individual customers. Nine months ended September 30, 2008 amounts reflect a reclassification of 18 thousand meters from residential to small business to conform to current presentation.

Competitive Electric Segment

Revenue and Commodity Hedging and Trading Activities


	Three Months Ended September 30,						% Change		Nine Months Ended September 30,						% Change
	2009			2008			% Change		2009			2008			% Change
Operating revenues:

Retail electricity revenues:
Residential	$	1,272		$	1,258		1.1		$	3,048		$	2,966		2.8
Small business (a)		366			335		9.3			924			852		8.5
Large business and other customers		330			447		(26.2	)		955			1,143		(16.4	)

Total retail electricity revenues		1,968			2,040		(3.5	)		4,927			4,961		(0.7	)
Wholesale electricity revenues (b)		380			1,134		(66.5	)		1,043			2,797		(62.7	)
Net sales (purchases) of balancing electricity to/from ERCOT		(5	)		(44	)	—			(50	)		(227	)	—
Amortization of intangibles (c)		20			26		(23.1	)		10			(15	)	—
Other operating revenues		70			102		(31.4	)		214			293		(27.0	)

Total operating revenues	$	2,433		$	3,258		(25.3	)	$	6,144		$	7,809		(21.3	)


Commodity hedging and trading activities:

Unrealized net gains (losses) from changes in fair value	$	136		$	6,068		—		$	1,026		$	(237	)	—
Unrealized net gains (losses) representing reversals of previously recognized fair values of positions settled in the current period		(116	)		20		—			(257	)		(68	)	—
Realized net gains (losses) on settled positions		103			(43	)	—			234			57		—

Total gain (loss)	$	123		$	6,045		—		$	1,003		$	(248	)	—

(a)	Customers with demand of less than 1 MW annually.

(b)

Upon settlement of physical derivative power sales and purchase contracts that are marked-to-market in net income, wholesale electricity revenues and fuel and purchased power costs are reported at approximated market prices, as required by accounting rules, instead of the contract price. As a result, these line item amounts include a noncash component, which the company considers “unrealized.” These amounts are as follows:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
Reported in revenues	$	(11	)	$	76		$	(135	)	$	155
Reported in fuel and purchased power costs		(6	)		(22	)		79			(71	)

Net gain (loss)	$	(17	)	$	54		$	(56	)	$	84

(c)	Represents amortization of the intangible net asset value of retail and wholesale power sales agreements resulting from purchase accounting.

Competitive Electric Segment

Production, Purchased Power and Delivery Cost Data


	Three Months Ended September 30,						% Change		Nine Months Ended September 30,						% Change
	2009			2008			% Change		2009			2008			% Change
Fuel, purchased power costs and delivery fees ($ millions):

Nuclear fuel	$	28		$	25		12.0		$	86		$	69		24.6
Lignite/coal		175			172		1.7			474			485		(2.3	)

Total baseload fuel		203			197		3.0			560			554		1.1
Natural gas fuel and purchased power (a)		431			1,161		(62.9	)		953			2,532		(62.4	)
Amortization of intangibles (b)		84			87		(3.4	)		224			246		(8.9	)
Other costs		39			94		(58.5	)		145			304		(52.3	)

Fuel and purchased power costs		757			1,539		(50.8	)		1,882			3,636		(48.2	)
Delivery fees (c)		430			384		12.0			1,105			1,010		9.4

Total	$	1,187		$	1,923		(38.3	)	$	2,987		$	4,646		(35.7	)


Fuel and purchased power costs (which excludes generation plant operating costs) per MWh:

Nuclear fuel	$	5.42		$	4.88		11.1		$	5.55		$	4.75		16.8
Lignite/coal (d)		16.53			15.39		7.4			16.49			15.83		4.2
Natural gas fuel and purchased power		47.99			104.02		(53.9	)		44.06			91.55		(51.9	)

Delivery fees per MWh	$	26.68		$	24.77		7.7		$	27.77		$	25.69		8.1

Production and purchased power volumes (GWh):

Nuclear		5,219			4,996		4.5			15,512			14,448		7.4
Lignite/coal		12,209			12,240		(0.3	)		32,914			33,697		(2.3	)

Total baseload generation		17,428			17,236		1.1			48,426			48,145		0.6
Natural gas-fueled generation		1,135			2,124		(46.6	)		2,168			3,843		(43.6	)
Purchased power		7,890			9,042		(12.7	)		19,523			23,816		(18.0	)

Total energy supply		26,453			28,402		(6.9	)		70,117			75,804		(7.5	)
Line loss and power imbalances (e)		370			408		(9.3	)		796			2,704		(70.6	)

Net energy supply volumes		26,083			27,994		(6.8	)		69,321			73,100		(5.2	)


Baseload capacity factors (%):

Nuclear		103.1	%		98.4	%	4.8			103.1	%		95.6	%	7.8
Lignite/coal		94.0	%		95.0	%	(1.1	)		85.9	%		87.7	%	(2.1	)
Total baseload		96.6	%		95.9	%	0.7			90.7	%		89.9	%	0.9

(a)	See note (b) on previous page.

(b)	Represents amortization of the intangible net asset values of emission credits, coal purchase contracts, nuclear fuel contracts and power purchase agreements and the stepped up value of nuclear fuel resulting from purchase accounting.

(c)	Includes delivery fee charges from Oncor that are eliminated in consolidation.

(d)	Includes depreciation and amortization of lignite mining assets, which is reported in the depreciation and amortization expense line item, but is part of overall fuel costs.

(e)	Includes physical purchases and sales, the financial results of which are reported in commodity hedging and trading activities in the income statement.

Competitive Electric Segment — Financial Results — Three Months Ended September 30, 2009 Compared to Three Months Ended September 30, 2008

Operating revenues decreased $825 million, or 25%, to $2.4 billion in 2009.

Wholesale electricity revenues decreased $754 million, or 66%, as compared to 2008, when wholesale revenues increased 93%. Volatility in wholesale revenues and purchased power costs reflects movements in natural gas prices, as lower natural gas prices in 2009 drove a 55% decline in average wholesale electricity sales prices. Reported wholesale revenues and purchased power costs also reflect changes in volumes of bilateral contracting activity entered into to mitigate the effects of demand volatility and congestion. Results in 2009 reflect lower demand volatility and a decline in congestion, which drove a 19% decrease in sales volumes. Realized gains in 2009 on hedging activities mitigated the effect of lower wholesale electricity prices (see discussion of results from commodity hedging and trading activities below).

Bilateral electricity contracting activity includes hedging transactions that utilize contracts for physical delivery. Wholesale sales and purchases of electricity are reported gross in the income statement if the transactions are scheduled for physical delivery with ERCOT.

Wholesale balancing activity represents intraday purchases and sales transactions with ERCOT for real-time balancing purposes, as measured in 15-minute intervals, which are highly variable and in 2009 reflected reduced volatility and congestion.

Retail electricity revenues declined $72 million, or 4%, to $1.968 billion in 2009 and reflected the following:

•

Lower average pricing contributed $154 million to the revenue decline, driven by the contract business market and also reflecting lower residential pricing. Lower average pricing reflected declines in wholesale electricity prices. In July 2009, the company announced retail residential price reductions of as much as 15% applicable to over 250,000 existing customers on month-to-month plans as well as reductions on offerings for new customers. The price reductions were effective in August 2009.

•

A four percent increase in retail sales volumes increased revenues by $82 million, reflecting increases in both the residential and business markets. Higher residential volumes reflected the effect of Hurricane Ike in 2008 and warmer weather in south Texas, while the higher business markets volume reflected customer mix changes.

•

Total retail electricity customer counts at September 30, 2009 decreased two percent from September 30, 2008 driven by a two percent decrease in the residential markets and reflecting competitive activity.

Other operating revenues decreased $32 million, or 31%, to $70 million in 2009 due to the effect of lower natural gas prices and lower volumes on sales of natural gas to industrial customers.

The change in operating revenues also reflected a $6 million decrease in amortization of intangible assets arising in purchase accounting.

Fuel, purchased power costs and delivery fees decreased $736 million, or 38%, to $1.2 billion in 2009. This decrease was driven by lower purchased power costs due to the effect of lower natural gas prices, decreased demand volatility and reduced congestion as discussed above regarding wholesale revenues. Lower costs of replacement power during unplanned generation unit repair outages contributed to improved margin. Other factors contributing to lower fuel and purchased power costs included lower natural gas-fueled generation and lower related fuel costs ($182 million) and the effect of lower natural gas prices and volumes on natural gas purchased for sale to industrial customers ($34 million).

Overall baseload generation production increased one percent in 2009 reflecting a five percent increase in nuclear production, partially offset by a small decrease in lignite/coal-fueled production. The increase in nuclear production, which reflects a refueling outage in 2008, resulted in improved margin.

Net gain (loss) from commodity hedging and trading activities include realized and unrealized gains and losses associated with financial instruments used for commodity hedging and trading purposes, as well as gains and losses on physical sales and purchases of commodities for trading and hedging purposes. A substantial majority of the commodity hedging activities are intended to mitigate the risk of commodity price movements on future revenues and involve natural gas positions entered into as part of the long-term hedging program. The results of these activities have been volatile because of the effects of movements in forward natural gas prices on unrealized mark-to-market valuations. Following is an analysis of amounts reported as net gain (loss) from commodity hedging and trading activities for the three months ended September 30, 2009 and 2008:

Three Months Ended September 30, 2009 — Unrealized mark-to-market net gains totaling $20 million included:

•

$4 million in net losses related to hedge positions, which includes $121 million in net gains from changes in fair value driven by the impact of lower forward natural gas prices on the value of positions in the long-term hedging program, and $125 million in net losses that represent reversals of previously recorded net gains on positions settled in the period, and

•

$24 million in net gains related to trading positions, which includes $15 million in net gains from changes in fair value and $9 million in net gains that represent reversals of previously recorded net losses on positions settled in the period.

Realized net gains totaling $103 million include:

•

$110 million in net gains related to positions that primarily hedged electricity revenues recognized in the period, and

•

$7 million in net losses related to trading positions.

Three Months Ended September 30, 2008 — Unrealized mark-to-market net gains totaling $6.088 billion include:

•

$6.091 billion in net gains related to hedge positions, which includes $6.074 billion in net gains from changes in fair value and $17 million in net gains that represent reversals of previously recorded net losses on positions settled in the period. The net gains from changes in fair value were driven by the effect of decreases in natural gas prices in forward periods on the value of positions in the long-term hedging program;

•

$10 million in “day one” losses related to large hedge positions (see Note 7 to Financial Statements), and

•

$7 million in net gains related to trading positions, which includes $4 million in net gains from changes in fair value and $3 million in net gains that represent reversals of previously recorded net losses on positions settled in the period.

Realized net losses totaling $43 million include:

•

$105 million in net losses related to hedge positions that primarily offset hedged electricity revenues recognized in the period, and

•

$62 million in net gains related to trading positions.

Operating costs increased $3 million, or 2%, to $161 million in 2009. The increase reflected $6 million in operational readiness costs in preparation for new lignite-fueled generation facilities start-up and $6 million in increased normal baseload maintenance costs in 2009, partially offset by $6 million in 2008 maintenance costs incurred for a planned nuclear generation unit outage and $3 million in lower costs in 2009 due to natural gas-fueled generation unit retirements.

Depreciation and amortization increased $7 million, or 2%, to $303 million in 2009. The increase was driven by $11 million in higher amortization expense related to the intangible asset representing retail customer relationships recorded in purchase accounting. Lower natural gas generation unit depreciation resulting from an impairment in 2008 was substantially offset by increased lignite generation unit depreciation as a result of normal capital additions as well as adjustments to useful lives of components.

SG&A expenses increased $20 million, or 12%, to $192 million in 2009 driven by a $19 million increase in retail bad debt expense. The increase in bad debt expense primarily reflects higher delinquencies due to delays in final bills and disconnects resulting from a system conversion, customer losses and general economic conditions.

Other income totaled $33 million in 2009 and $2 million in 2008. The 2009 amount included a $23 million reversal of a use tax accrual (see Note 13 to Financial Statements) and a $6 million fee received related to an interest rate swap/commodity hedge derivative agreement. Other deductions totaled $7 million in 2009 and $533 million in 2008. The 2008 other deductions amount includes $499 million in impairment charges related to NOx and SO₂ environmental allowances intangible assets and $26 million in charges to reserve for net receivables (excluding termination related costs) from terminated hedging transactions with subsidiaries of Lehman Brothers Holdings Inc., which filed for bankruptcy under Chapter 11 of the US Bankruptcy Code. See Note 13 to Financial Statements.

Interest expense and related charges increased $193 million, or 32%, to $798 million in 2009 reflecting a $138 million unrealized mark-to-market net loss in 2009 compared to a $36 million net gain in 2008 related to interest rate swaps and a $39 million increase in noncash amortization of losses on interest rate swaps dedesignated as cash flow hedges in August 2008, partially offset by $14 million in lower amortization of discount and debt issuance costs and $6 million in increased capitalized interest.

Income tax benefit totaled $21 million in 2009 compared to income tax expense totaling $2.001 billion in 2008. The effective rates were 32.3% in 2009 and 35.7% in 2008. The decrease in the rate is primarily due to the effect of interest accrued for uncertain tax positions on a small loss in 2009.

Results for the segment declined by $3.7 billion to a loss of $44 million driven by the decrease in unrealized mark-to-market net gains related to commodity hedging activities and the unrealized mark-to-market net loss related to interest rate swaps in 2009 reported in interest expense and related charges, partially offset by the effect of impairment charges reported in other deductions in 2008.

Competitive Electric Segment — Financial Results — Nine Months Ended September 30, 2009 Compared to Nine Months Ended September 30, 2008

Operating revenues decreased $1.7 billion, or 21%, to $6.1 billion in 2009.

Wholesale electricity revenues decreased $1.8 billion, or 63%, as compared to 2008 when revenues increased 78%. Volatility in wholesale revenues and purchased power costs reflects movements in natural gas prices, as lower natural gas prices in 2009 drove a 48% decline in average wholesale electricity sales prices. Reported wholesale revenues and purchased power costs also reflect changes in volumes of bilateral contracting activity entered into to mitigate the effects of demand volatility and congestion. Results in 2009 reflect lower demand volatility and a decline in congestion, which drove a 15% decline in wholesale sales volumes. Realized gains in 2009 on hedging activities mitigated the effect of lower wholesale electricity prices (see discussion of commodity hedging and trading activities below).

Retail electricity revenues declined $34 million, or 1%, to $4.927 billion and reflected the following:

•

Lower average pricing contributed $103 million to the revenue decline. The change in average pricing reflected lower average contracted business rates driven by lower wholesale electricity prices, partially offset by higher average pricing in the residential and non-contract business markets resulting from advanced meter surcharges as well as customer mix.

•

Retail sales volume growth of 1% increased revenues by $69 million. Volumes rose in both the residential and business markets.

Other operating revenues decreased $79 million, or 27%, to $214 million in 2009 due to the effect of lower natural gas prices and lower volumes on sales of natural gas to industrial customers.

The change in operating revenues also reflected a $25 million increase in amortization of intangible assets arising in purchase accounting.

Fuel, purchased power costs and delivery fees decreased $1.7 billion, or 36%, to $3.0 billion in 2009. This decrease was driven by lower purchased power costs due to the effect of lower natural gas prices, decreased demand volatility and reduced congestion as discussed above regarding wholesale revenues. Lower costs of replacement power during unplanned generation unit repair outages contributed to improved margin. Other factors contributing to lower fuel and purchased power costs included lower natural gas-fueled generation and lower related fuel costs ($372 million), the effect of lower natural gas prices on natural gas purchased for sale to industrial customers ($111 million) and lower amortization of intangible assets arising in purchase accounting ($22 million).

Overall baseload generation production increased 1% in 2009 reflecting a seven percent increase in nuclear production, partially offset by a two percent decrease in lignite/coal-fueled production. The increase in nuclear production, which reflects a refueling outage in 2008, resulted in improved margin. The decrease in lignite/coal-fueled production reflected reductions during certain periods when power could be purchased in the wholesale market at prices below production costs, which was largely due to lower natural gas prices and higher wind generation availability, partially offset by lower maintenance and repair outages.

Following is an analysis of amounts reported as net gain (loss) from commodity hedging and trading activities for the nine months ended September 30, 2009 and 2008:

Nine Months Ended September 30, 2009 — Unrealized mark-to-market net gains totaling $769 million included:

•

$750 million in net gains related to hedge positions, which includes $1.010 billion in net gains from changes in fair value, driven by the impact of lower forward natural gas prices on the value of positions in the long-term hedging program, and $260 million in net losses that represent reversals of previously recorded net gains on positions settled in the period, and

•

$19 million in net gains related to trading positions, which includes $16 million in net gains from changes in fair value and $3 million in net gains that represent reversals of previously recorded net losses on positions settled in the period.

Realized net gains totaling $234 million included:

•

$247 million in net gains related to positions that primarily hedged electricity revenues recognized in the period, and

•

$13 million in net losses related to trading positions.

Nine Months Ended September 30, 2008 — Unrealized mark-to-market net losses totaling $305 million included:

•

$250 million in net losses related to hedge positions, which includes $248 million in net losses from changes in fair value and $2 million in net losses that represent reversals of previously recorded net gains on positions settled in the period;

•

$69 million in “day one” net losses related to large hedge positions (see Note 7 to Financial Statements), and

•

$13 million in net gains related to trading positions, which includes $79 million in net gains from changes in fair value and $66 million in net losses that represent reversals of previously recorded net gains on positions settled in the period.

Realized net gains totaling $57 million include:

•

$76 million in net losses related to hedge positions that offset hedged electricity revenues and fuel and purchased power costs recognized in the period, and

•

$133 million in net gains related to trading positions.

Operating costs increased $4 million, or 1%, to $504 million in 2009. The increase reflected $21 million in higher maintenance costs incurred during planned and unplanned lignite-fueled generation unit outages in 2009 and $15 million in operational readiness costs incurred in preparation for new lignite-fueled generation facilities start-up, partially offset by the effect of $32 million in 2008 maintenance costs incurred for a planned nuclear generation unit outage.

Depreciation and amortization increased $35 million, or 4%, to $862 million in 2009. The increase was driven by $29 million in higher amortization expense related to the intangible asset representing retail customer relationships recorded in purchase accounting. Increased lignite generation unit depreciation as a result of normal capital additions as well as adjustments to useful lives of components was substantially offset by lower natural gas generation unit depreciation resulting from an impairment in 2008.

SG&A expenses increased $56 million, or 11%, to $555 million in 2009. The increase reflected $30 million in higher retail bad debt expense, reflecting higher delinquencies due to delays in final bills and disconnects resulting from a system conversion, customer losses and general economic conditions, $25 million in higher costs associated with the implementation of a new retail customer information management system and the transition of certain previously outsourced customer operations and $4 million in costs related to the nuclear generation development joint venture.

See Note 2 to Financial Statements for discussion of the additional impairment of goodwill of $70 million in 2009.

Other income totaled $38 million in 2009 and $8 million in 2008. The 2009 amount included a $23 million reversal of a use tax accrual (see Note 13 to Financial Statements) and a $6 million fee received related to an interest rate swap/commodity hedge derivative agreement. Other deductions totaled $22 million in 2009 and $559 million in 2008. The 2009 amount includes charges for severance and other individually immaterial miscellaneous expenses. The 2008 amount includes $501 million in impairment charges related to NOx and SO₂ environmental allowances intangible assets and $26 million in charges to reserve for net receivables (excluding termination related costs) from terminated hedging transactions with subsidiaries of Lehman Brothers Holdings Inc., which filed for bankruptcy under Chapter 11 of the US Bankruptcy Code. See Note 13 to Financial Statements for more details.

Interest expense and related charges decreased $410 million, or 22%, to $1.4 billion in 2009. The decrease reflected $491 million in higher unrealized mark-to-market net gains related to interest rate swaps and $32 million in increased capitalized interest, partially offset by $123 million in increased noncash amortization of losses on interest rate swaps dedesignated as cash flow hedges in August 2008.

Income tax expense totaled $301 million in 2009 compared to an income tax benefit totaling $452 million in 2008. The effective rate was 40.8% on income in 2009 and 34.4% on a loss in 2008. The increase in the rate reflects the impacts of the non-deductible goodwill impairment in 2009, which added 3.5 percentage points to the effective rate, and the effect of interest accrued for uncertain tax positions, which increased the rate on income in 2009 and decreased the rate on a loss in 2008.

Results for the segment improved $1.3 billion to net income of $436 million in 2009 driven by the change in unrealized mark-to-market results related to commodity hedging activities, the 2008 impairment charges reported in other deductions related to environmental allowances intangible assets and the unrealized mark-to-market net gains related to interest rate swaps reported in interest expense.

Regulated Delivery Segment

Financial Results


	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
Operating revenues	$	770		$	728		$	2,037		$	1,969
Operating costs		(228	)		(213	)		(668	)		(620	)
Depreciation and amortization		(147	)		(128	)		(405	)		(370	)
Selling, general and administrative expenses		(50	)		(42	)		(139	)		(126	)
Franchise and revenue-based taxes		(67	)		(67	)		(185	)		(186	)
Other income		10			12			30			34
Other deductions		(29	)		(3	)		(32	)		(17	)
Interest income		13			12			32			34
Interest expense and related charges		(85	)		(80	)		(258	)		(229	)

Income before income taxes		187			219			412			489
Income tax expense (a)		(55	)		(80	)		(140	)		(180	)

Net income	$	132		$	139		$	272		$	309

(a)

Effective with the sale of noncontrolling interests (see Note 6 to Financial Statements), Oncor is taxed as a partnership and thus not subject to income taxes; however, subsequent to the sale, Oncor reflects a “provision in lieu of income taxes,” and the results of segments are evaluated as if they were stand-alone entities filing income tax returns.

Operating Data


	Three Months Ended September 30,				% Change		Nine Months Ended September 30,				% Change
	2009		2008		% Change		2009		2008		% Change
Operating statistics:
Electric energy billed volumes (GWh)		32,017		32,611	(1.8	)		80,189		83,859	(4.4	)

Reliability statistics (a):
System Average Interruption Duration Index (SAIDI) (nonstorm)								91.0		82.6	10.2
System Average Interruption Frequency Index (SAIFI) (nonstorm)								1.2		1.1	9.1
Customer Average Interruption Duration Index (CAIDI) (nonstorm)								77.1		75.3	2.4

Electricity points of delivery (end of period and in thousands):
Electricity distribution points of delivery (based on number of meters)								3,142		3,116	0.8

	Three Months Ended September 30,				% Change		Nine Months Ended September 30,				% Change
	2009		2008		% Change		2009		2008		% Change
Operating revenues:
Electricity distribution revenues (b):
Affiliated (TCEH)	$	308	$	290	6.2		$	783	$	773	1.3
Nonaffiliated		378		355	6.5			1,004		960	4.6

Total distribution revenues		686		645	6.4			1,787		1,733	3.1
Third-party transmission revenues		76		72	5.6			225		207	8.7
Other miscellaneous revenues		8		11	(27.3	)		25		29	(13.8	)

Total operating revenues	$	770	$	728	5.8		$	2,037	$	1,969	3.5

(a)

SAIDI is the average number of minutes electric service is interrupted per consumer in a year. SAIFI is the average number of electric service interruptions per consumer in a year. CAIDI is the average duration in minutes per electric service interruption in a year. The statistics presented are based on twelve months ended September 30, 2009 and 2008 data.

(b)

Includes transition charge revenue associated with the issuance of securitization bonds totaling $44 million and $40 million for the three months ended September 30, 2009 and 2008, respectively, and $113 million and $108 million for the nine months ended September 30, 2009 and 2008, respectively. Also includes disconnect/reconnect fees and other discretionary revenues for services requested by REPs.

Financial Results — Three Months Ended September 30, 2009 Compared to Three Months Ended September 30, 2008

Operating revenues increased $42 million, or 6%, to $770 million in 2009. The increase reflected:

•

$12 million from increased rates implemented upon the PUCT’s approval of new tariffs in September 2009 (see “Regulation and Rates”);

•

$8 million from increased distribution tariffs to recover higher transmission costs;

•

$7 million from a surcharge to recover advanced metering deployment costs and $3 million from a surcharge to recover additional energy efficiency costs, both of which became effective with the January 2009 billing cycle;

•

an estimated $5 million impact from growth in points of delivery;

•

$4 million in higher transmission revenues primarily due to a rate increase to recover ongoing investment in the transmission system;

•

$4 million in higher charges to REPs related to transition bonds (with a related increase in amortization of the related regulatory asset), and

•

an increase in estimated average customer usage that was largely offset by the estimated effects of milder weather.

Operating costs increased $15 million, or 7%, to $228 million in 2009. The increase reflected a $10 million in higher fees paid to other transmission entities and $2 million in costs related to programs designed to improve customer electricity demand efficiency, both of which have related revenue increases.

Depreciation and amortization increased $19 million, or 15%, to $147 million in 2009. The increase reflected $12 million in higher depreciation due to ongoing investments in property, plant and equipment, $4 million in higher amortization of regulatory assets associated with securitization bonds (with an offsetting increase in revenues) and $3 million due to increased depreciation and amortization rates implemented upon the PUCT approval of new tariffs in September 2009.

SG&A expenses increased $8 million, or 19%, to $50 million in 2009. The increase reflected $5 million in higher professional and contractor fees driven by outsourcing transition and CREZ development activities.

Other income totaled $10 million in 2009 and $12 million in 2008. The amounts reflected accretion of an adjustment (discount) to regulatory assets resulting from purchase accounting. See “Oncor’s Regulatory Assets and Liabilities” in Note 13 to Financial Statements.

Other deductions totaled $29 million in 2009 and $3 million in 2008. The 2009 amount included a $25 million write off of regulatory assets (see Note 13 to Financial Statements) and costs totaling $1 million associated with the 2006 settlement with certain cities related to rates.

Interest income increased $1 million, or 8%, to $13 million in 2009. The increase reflected higher earnings on investments held for employee benefit plans, partially offset by a decrease in reimbursement of transition bond interest from TCEH reflecting lower remaining principal amounts of the bonds.

Interest expense and related charges increased $5 million, or 6%, to $85 million in 2009. The increase reflected $4 million in higher average borrowings, reflecting ongoing capital investments, and $1 million due to higher average interest rates.

Income tax expense totaled $55 million in 2009 compared to $80 million in 2008. The effective rate decreased to 29.4% in 2009 from 36.5% in 2008. The decrease in the rate was driven by the reversal of accrued interest due to the favorable resolution of uncertain tax positions. The decreased rate also reflects the effect of investment gains and losses on certain employee benefit plans, which are excluded in determining taxable income.

Net income decreased $7 million, or 5%, to $132 million in 2009 driven by the write off of certain regulatory assets, partially offset by the decrease in the effective income tax rate.

Financial Results — Nine Months Ended September 30, 2009 Compared to Nine Months Ended September 30, 2008

Operating revenues increased $68 million, or 3%, to $2.037 billion in 2009. The increase reflected:

•

$30 million from increased distribution tariffs to recover higher transmission costs;

•

$19 million in higher transmission revenues primarily due to a rate increase to recover ongoing investment in the transmission system;

•

$13 million from a surcharge to recover advanced metering deployment costs and $8 million from a surcharge to recover additional energy efficiency costs, both of which became effective with the January 2009 billing cycle;

•

an estimated $13 million impact from growth in points of delivery, and

•

$12 million from increased rates implemented upon the PUCT’s approval of new tariffs in September 2009 (see “Regulation and Rates”),

partially offset by an estimated $26 million in lower average consumption primarily due to the effects of milder weather and general economic conditions.

Operating costs increased $48 million, or 8%, to $668 million in 2009. The increase reflected $36 million in higher fees paid to other transmission entities and $7 million in costs related to programs designed to improve customer electricity demand efficiency, both of which have related revenue increases, $5 million in higher labor costs to meet enhanced service terms and conditions and $3 million in higher smart grid services costs.

Depreciation and amortization increased $35 million, or 9%, to $405 million in 2009. The increase reflected $28 million in higher depreciation due to ongoing investments in property, plant and equipment, $5 million in higher amortization of regulatory assets associated with securitization bonds (with an offsetting increase in revenues) and $3 million due to increased depreciation and amortization rates implemented upon the PUCT approval of new tariffs in September 2009.

SG&A expenses increased $13 million, or 10%, to $139 million in 2009. The increase reflected $10 million in higher professional and contractor fees driven by outsourcing transition and CREZ development activities and $4 million in higher costs related to certain benefit plans, partially offset by a $3 million one-time reversal of bad debt expense due to the PUCT’s finalization of the Certification of Retail Electric Providers rule in April 2009. Write-offs of uncollectible amounts owed by nonaffiliated REPs are deferred as a regulatory asset (see “Regulation and Rates”).

Other income totaled $30 million in 2009 and $34 million in 2008. The amounts reflected accretion of an adjustment (discount) to regulatory assets resulting from purchase accounting. See “Oncor’s Regulatory Assets and Liabilities” in Note 13 to Financial Statements for additional information.

Other deductions totaled $32 million in 2009 and $17 million in 2008. The 2009 amount included a $25 million write off of regulatory assets (see Note 13 to Financial Statements). The 2009 and 2008 amounts included costs totaling $2 million and $13 million, respectively, associated with the 2006 settlement with certain cities related to rates.

Interest income decreased $2 million, or 6%, to $32 million in 2009. The decrease reflected lower reimbursement of transition bond interest from TCEH due to lower remaining principal amounts of the bonds, partially offset by higher earnings on investments held for certain employee benefit plans.

Interest expense and related charges increased $29 million, or 13%, to $258 million in 2009. The increase reflected $15 million due to higher average interest rates, which was driven by refinancing of short-term borrowings with $1.5 billion of senior secured notes issued in September 2008. The majority of the proceeds of the September 2008 notes issuance was used to pay outstanding short-term borrowings under Oncor’s credit facility. The increase also reflected $14 million in higher average borrowings, reflecting ongoing capital investments.

Income tax expense totaled $140 million in 2009 compared to $180 million in 2008. The effective rate decreased to 34.0% in 2009 from 36.8% in 2008. The decrease in the rate was driven by the reversal of accrued interest due to the favorable resolution of uncertain tax positions.

Net income decreased $37 million, or 12%, to $272 million in 2009 driven by the effect of lower average consumption on revenues, the write off of certain regulatory assets and increased interest expense.

Energy-Related Commodity Contracts and Mark-to-Market Activities

The table below summarizes the changes in commodity contract assets and liabilities for the nine months ended September 30, 2009. The net change in these assets and liabilities totaling $712 million, excluding “other activity” as described below, represents the pretax effect on earnings of positions in the commodity contract portfolio that are marked-to-market in net income (see Note 7 to Financial Statements). These positions represent both economic hedging and trading activities.


	Nine Months Ended September 30, 2009
Commodity contract net asset at beginning of period	$	430

Settlements of positions (a)		(314	)

Unrealized mark-to-market valuations due to changes in fair value (b)		1,026

Other activity (c)		63


Commodity contract net asset at end of period (d)	$	1,205

(a)

Represents reversals of previously recognized unrealized gains and losses upon settlement (offsets realized gains and losses recognized in the settlement period).

(b)

Primarily represents mark-to-market effects of positions in the long-term hedging program (see discussion above under “Long-Term Hedging Program”).

(c)

This amount does not represent unrealized gains or losses. Includes initial values of positions involving the receipt or payment of cash or other consideration.

(d)

Amount excludes $12 million in net derivative liabilities related to instruments not marked-to-market in net income.

In addition to the effect on net income of recording unrealized mark-to-market gains and losses that are reflected in the table above, similar effects arise in the recording of unrealized ineffectiveness gains and losses associated with commodity-related positions accounted for as cash flow hedges. These effects on net income, which include reversals of previously recorded unrealized ineffectiveness gains and losses to offset realized gains and losses upon settlement, are reflected in the balance sheet as changes in cash flow hedge and other derivative assets and liabilities (see Note 7 to Financial Statements). The total pretax effect of recording unrealized gains and losses in net income related to commodity contracts is summarized as follows:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
Unrealized gains/(losses) related to contracts marked-to-market	$	3	$	6,142	$	712	$	(217	)

Ineffectiveness gains/losses related to cash flow hedges		—		—		1		(4	)


Total unrealized gains (losses) related to commodity contracts	$	3	$	6,142	$	713	$	(221	)

Maturity Table — Following are the components of the net commodity contract asset at September 30, 2009:


	Amount
Net commodity contract asset	$	1,205

Net asset associated with receipts of natural gas under physical gas exchange transactions		4


Amount of net asset arising from mark-to-market accounting	$	1,209

The following table presents the net commodity contract asset arising from recognition of fair values under mark-to-market accounting as of September 30, 2009, scheduled by the source of fair value and contractual settlement dates of the underlying positions.


	Maturity dates of unrealized net commodity contract asset at September 30, 2009
Source of fair value	Less than 1 year			1-3 years			4-5 years			Excess of 5 years			Total
Prices actively quoted	$	(12	)	$	(80	)	$	(2	)	$	—		$	(94	)
Prices provided by other external sources		704			572			56			—			1,332
Prices based on models		(10	)		(29	)		140			(130	)		(29	)

Total	$	682		$	463		$	194		$	(130	)	$	1,209

Percentage of total fair value		57	%		38	%		16	%		(11	)%		100	%

The “prices actively quoted” category reflects only exchange traded contracts for which active quotes are readily available. The “prices provided by other external sources” category represents forward commodity positions valued using prices for which over-the-counter broker quotes are available in active markets. Over-the-counter quotes for power in ERCOT that are deemed active markets (excluding the West zone) generally extend through 2012 and over-the-counter quotes for natural gas generally extend through 2015, depending upon delivery point. The “prices based on models” category contains the value of all nonexchange traded options, valued using option pricing models. In addition, this category contains other contractual arrangements that may have both forward and option components, as well as other contracts that are valued using proprietary long-term pricing models that utilize certain market based inputs. See Note 8 to Financial Statements for fair value disclosures and discussion of fair value measurements.

FINANCIAL CONDITION — LIQUIDITY AND CAPITAL RESOURCES

Consolidated Cash Flows — Nine Months Ended September 30, 2009 Compared to Nine Months Ended September 30, 2008

Cash provided by operating activities for the nine months ended September 30, 2009 totaled $1.743 billion compared to cash provided of $957 million in the nine months ended September 30, 2008. The increase in cash provided of $786 million was driven by:

•

a $496 million favorable change in margin deposits primarily due to the effect of lower forward natural gas prices on positions in the long-term hedging program;

•

a $220 million decrease in cash interest paid due to the payment of approximately $233 million of interest with new notes instead of cash as discussed under “PIK Interest Election” below, and

•

a $51 million favorable impact of timing of advanced metering surcharges.

Cash provided by financing activities decreased $2.632 billion as summarized below and reflected lower borrowing to support margin deposits:


	Nine Months Ended September 30,
	2009		2008
Net issuances, repayments and repurchases of borrowings	$	389	$	2,986
Net issuances of common stock		—		33
Net contributions from and distributions to noncontrolling interests		10		—
Other		21		33

Total provided by financing activities	$	420	$	3,052

Cash used in investing activities decreased $247 million as summarized below:


	Nine Months Ended September 30,
	2009			2008
Capital expenditures, including nuclear fuel	$	(2,004	)	$	(2,179	)
Money market fund redemptions (investments)		142			(242	)
Investment posted with derivative counterparty (Note 7)		(400	)		—
Change in restricted cash		107			1
Other		28			46

Total used in investing activities	$	(2,127	)	$	(2,374	)

The decline in capital spending for the nine months ended September 30, 2009 as compared to the nine months ended September 30, 2008 primarily reflected a decrease in spending related to the construction of new generation facilities, which is nearing completion, partially offset by capital expenditures for advanced metering deployment.

Depreciation and amortization expense reported in the statement of cash flows exceeds the amount reported in the statement of income by $452 million and $337 million for the nine months ended September 30, 2009 and 2008, respectively. The differences represent amortization of intangible net assets and debt fair value discounts arising from purchase accounting that is reported in various other income statement line items including operating revenues, fuel and purchased power costs and delivery fees, other income and interest expense and related charges. The differences also reflect the amortization of nuclear fuel, which is reported as fuel cost in the statement of income consistent with industry practice. In addition, the differences reflect the amortization of losses on dedesignated cash flow hedges, which is reported in interest expense and related charges in the statement of income, and the regulatory asset amortization resulting from the final PUCT order in the Oncor rate case that is reported in operating costs in the statement of income (see Note 13 to Financial Statements).

Debt Financing Activity — Activities related to short-term borrowings and long-term debt during the nine months ended September 30, 2009 are as follows (all amounts presented are principal, repayments and repurchases include amounts related to capital leases and exclude amounts related to debt discount, financing and reacquisition expenses):


	Borrowings (a)		Repayments and Repurchases
TCEH	$	522	$	215
EFC Holdings		—		2
EFH Corp.		—		10
Oncor		—		70

Total long-term		522		297

TCEH		—		—
Oncor		200		—

Total short-term (b)		200		—

Total	$	722	$	297

(a)

Excludes $150 million of EFH Corp. Toggle Notes and $98 million of TCEH Toggle Notes issued in May 2009 in payment of accrued interest as discussed below under “PIK Interest Election.”

(b)

Short-term amounts represent net borrowings/repayments.

See Note 4 to Financial Statements for further detail of long-term debt and other financing arrangements.

We or our affiliates may from time to time purchase our outstanding debt securities for cash in open market purchases or privately negotiated transactions, or we may refinance existing debt securities. We will evaluate any such transactions in light of market prices of the securities, taking into account liquidity requirements and prospects for future access to capital, contractual restrictions and other factors. The amounts involved in any such transactions, individually or in the aggregate, may be material. See Note 4 to Financial Statements for discussion of debt exchange offers and consent solicitations announced in October 2009.

Available Liquidity — The following table summarizes changes in available liquidity for the nine months ended September 30, 2009.


	Available Liquidity
	September 30, 2009		December 31, 2008		Change
Cash and cash equivalents, excluding Oncor	$	1,703	$	1,564	$	139
Investments held in money market fund		—		142		(142	)
TCEH Delayed Draw Term Loan Facility		—		522		(522	)
TCEH Revolving Credit Facility (a)		1,736		1,767		(31	)
TCEH Letter of Credit Facility		459		490		(31	)

Subtotal	$	3,898	$	4,485	$	(587	)
Short-term investment (b)		482		—		482

Total liquidity, excluding Oncor (c)	$	4,380	$	4,485	$	(105	)

Cash and cash equivalents – Oncor	$	22	$	125	$	(103	)
Oncor Revolving Credit Facility		1,341		1,508		(167	)

Total Oncor liquidity	$	1,363	$	1,633	$	(270	)

(a)	As of September 30, 2009 and December 31, 2008, the TCEH Revolving Credit Facility includes $141 million and $144 million, respectively, of commitments from Lehman that are only available from the fronting banks and the swingline lender.

(b)	Includes $417 million cash investment (including accrued interest) and $65 million in letters of credit posted related to certain interest rate and commodity hedge transactions. This collateral will be returned no later than March 2010. See Note 7 to Financial Statements.

(c)

Pursuant to PUCT rules, TCEH is required to maintain available liquidity to assure adequate credit worthiness of TCEH’s REP subsidiaries, including the ability to return retail customer deposits, if necessary. As a result, at September 30, 2009, the total availability under the TCEH credit facilities should be further reduced by $237 million. See “Regulation and Rates – Certification of REPs.”

Note: Available liquidity above does not include the amounts available from exercising the payment-in-kind (PIK) option on the EFH Corp. Toggle Notes and TCEH Toggle Notes, which for the remaining payment dates from November 2009 through November 2012 could add approximately $1.6 billion of liquidity.

The $105 million decrease in available liquidity excluding Oncor, after taking into account the short-term investment, was driven by capital spending to construct the new generation facilities.

The decrease in available liquidity for Oncor of $270 million in the nine months ended September 30, 2009 reflected ongoing capital investment in transmission and distribution infrastructure.

See Note 4 to Financial Statements for additional discussion of these credit facilities.

Pension and OPEB Plan Funding — Pension and OPEB plan funding is expected to total $79 million and $22 million, respectively, in 2009. Oncor is expected to fund approximately 80% of these amounts. We made pension and OPEB contributions of $61 million and $16 million, respectively, in the nine months ended September 30, 2009.

PIK Interest Election — EFH Corp. and TCEH have the option every six months at their discretion, ending with the payment due November 2012, to use the payment-in-kind (PIK) feature of their respective toggle notes in lieu of making cash interest payments. Once EFH Corp. and/or TCEH make a PIK election, the election is valid for each succeeding interest payment period until EFH Corp. and/or TCEH revoke the applicable election. We elected to do so for the May 2009, November 2009 and May 2010 interest payments as an efficient and cost-effective method to further enhance liquidity, in light of the weaker economy and related lower electricity demand and the continuing uncertainty in the financial markets. Use of the PIK feature will be evaluated at each election period, taking into account market conditions and other relevant factors at such time.

EFH Corp. made its May 2009 interest payment and will make its November 2009 and May 2010 interest payments by using the PIK feature of the EFH Corp. Toggle Notes. During the applicable interest periods, the interest rate on the toggle notes is increased from 11.25% to 12.00%. EFH Corp. increased the aggregate principal amount of the EFH Corp. Toggle Notes by $150 million in May 2009 and will further increase the aggregate principal amount of the EFH Corp. Toggle Notes by $159 million in November 2009 and by $169 million in May 2010. The elections increased liquidity as of May 1, 2009 by an amount equal to approximately $141 million and will further increase liquidity as of November 1, 2009 and May 1, 2010 by an amount equal to approximately $149 million and $158 million, respectively, with such amounts constituting the amount of cash interest that otherwise would have been payable on the respective dates, and will increase the expected annual cash interest expense by approximately $54 million, constituting the additional cash interest that will be payable with respect to the $478 million of additional toggle notes. See Note 4 to Financial Statements for discussion of debt exchange offers that may result in redemption of portions of the outstanding principal of these notes and a reduction of the effect of the PIK election for the May 2010 interest payment.

Similarly, TCEH made its May 2009 interest payment and will make its November 2009 and May 2010 interest payments by using the PIK feature of the TCEH Toggle Notes. During the applicable interest periods, the interest rate on the toggle notes is increased from 10.50% to 11.25%. TCEH increased the aggregate principal amount of the TCEH Toggle Notes by approximately $98.5 million in May 2009 and will further increase the aggregate principal amount of the TCEH Toggle Notes by approximately $104 million in November 2009 and $110 million in May 2010. The elections increased liquidity as of May 1, 2009 by an amount equal to approximately $92 million and will further increase liquidity as of November 1, 2009 and May 1, 2010 by an amount equal to approximately $97 million and $103 million, respectively, with such amounts constituting the amount of cash interest that otherwise would have been payable on the respective dates, and will increase the expected annual cash interest expense by approximately $33 million, constituting the additional cash interest that will be payable with respect to the $312 million of additional toggle notes.

Liquidity Effects of Commodity Hedging and Trading Activities — Commodity hedging and trading transactions typically require a counterparty to post collateral if the forward price of the underlying commodity moves such that the hedging or trading instrument held by such counterparty has declined in value. TCEH uses cash, letters of credit and other forms of credit support to satisfy such collateral obligations. In addition, TCEH’s Commodity Collateral Posting Facility, an uncapped senior secured revolving credit facility, funds the cash collateral posting requirements for a significant portion of the positions in the long-term hedging program not otherwise secured by a first-lien in the assets of TCEH. The aggregate principal amount of this facility is determined by the exposure arising from higher forward market prices, regardless of the amount of such exposure, on a portfolio of certain natural gas hedging transaction volumes. Including those hedging transactions where margin deposits are covered by unlimited borrowings under the TCEH Commodity Collateral Posting Facility, at September 30, 2009, more than 95% of the long-term natural gas hedging program transactions were secured by a first-lien interest in the assets of TCEH that is pari passu with the TCEH Senior Secured Facilities, the effect of which is a significant reduction in the liquidity exposure associated with collateral requirements for those hedging transactions. See Note 4 to Financial Statements for more information about this facility.

As of September 30, 2009, TCEH received or posted cash and letters of credit for commodity hedging and trading activities as follows:

•

$151 million in cash has been posted with counterparties for exchange cleared transactions (including initial margin), as compared to $317 million posted as of December 31, 2008;

•

$497 million in cash has been received from counterparties, net of $7 million in cash posted, for over-the-counter and other non-exchange cleared transactions, as compared to $402 million received, net of $122 million in cash posted, as of December 31, 2008;

•

$360 million in letters of credit have been posted with counterparties, as compared to $342 million posted as of December 31, 2008, and

•

$10 million in letters of credit have been received from counterparties, as compared to $30 million received as of December 31, 2008.

In addition, EFH Corp. (parent) elected to post cash collateral of $400 million in 2009 related to certain TCEH interest rate and commodity hedge transactions (see Note 7 to Financial Statements).

With respect to exchange cleared transactions, these transactions typically require initial margin (i.e. the upfront cash and/or letter of credit posted to take into account the size and maturity of the positions and credit quality) in addition to variance margin (i.e. the daily cash margin posted to take into account changes in the value of the underlying commodity). The amount of initial margin required is generally defined by exchange rules. Clearing agents, however, typically have the right to request additional initial margin based on various factors including market depth, volatility and credit quality, which may be in the form of cash, letters of credit, a guaranty or other forms as negotiated with the clearing agent. With respect to cash collateral that is received, such cash collateral is either used for working capital and other corporate purposes, including reducing short-term borrowings under credit facilities, or it is required to be deposited in a separate account and restricted from being used for working capital and other corporate purposes. With respect to over-the-counter transactions, counterparties generally have the right to substitute letters of credit for such cash collateral. In such event, the cash collateral previously posted would be returned to such counterparties thereby reducing liquidity in the event that it was not restricted. As of September 30, 2009, restricted cash collateral was less than $1 million. See Note 13 to Financial Statements regarding restricted cash.

With the long-term hedging program, increases in natural gas prices generally result in increased cash collateral and letter of credit margin requirements. As of September 30, 2009, approximately 0.7 billion MMBtu of positions related to the long-term hedging program were not directly secured on an asset-lien basis and thus have cash collateral posting requirements. The uncapped TCEH Commodity Collateral Posting Facility supports the collateral posting requirements related to these transactions.

Income Tax Refunds/Payments — In February 2009, we received a refund totaling $98 million in income taxes and related interest related to IRS audits of 1993 and 1994 federal income tax returns. No material federal income tax payments or refunds are anticipated within the next twelve months. We made payments totaling approximately $51 million related to the Texas margin tax in May and August 2009. Tax payments for the Texas margin tax are expected to be approximately $57 million within the next twelve months.

Sale of Accounts Receivable — TXU Energy participates in an accounts receivable securitization program, the activity under which is accounted for as a sale of accounts receivable in accordance with transfers and servicing accounting standards. Under the program, TXU Energy (originator) sells retail trade accounts receivable to TXU Receivables Company, a consolidated wholly-owned bankruptcy-remote direct subsidiary of EFH Corp., which sells undivided interests in the purchased accounts receivable for cash to special purpose entities established by financial institutions. All new trade receivables under the program generated by the originator are continuously purchased by TXU Receivables Company with the proceeds from collections of receivables previously purchased. Funding under the program totaled $700 million and $416 million at September 30, 2009 and December 31, 2008, respectively. See Note 3 to Financial Statements for a more complete description of the program including the impact of the program on the financial statements for the periods presented and the contingencies that could result in a reduction of funding available under the program.

Financial Covenants, Credit Rating Provisions and Cross Default Provisions — The terms of certain of our financing arrangements contain maintenance covenants with respect to leverage ratios and/or minimum net worth. As of September 30, 2009, we were in compliance with all such maintenance covenants.

Covenants and Restrictions under Financing Arrangements — Each of the TCEH Senior Secured Facilities, indentures governing the TCEH Senior Notes and the EFH Corp. Senior Notes and agreements related to certain series of TCEH’s pollution control revenue bonds contains covenants that could have a material impact on the liquidity and operations of EFH Corp. and its subsidiaries. See the 2008 Form 10-K for additional discussion of the covenants contained in these financing arrangements.

Adjusted EBITDA (as used in the restricted payments covenant contained in the indenture governing the EFH Corp. Senior Notes) for the twelve months ended September 30, 2009 totaled $4.8 billion for EFH Corp. See Exhibit 99(b) and 99(c) for a reconciliation of net income to Adjusted EBITDA for EFH Corp. and TCEH, respectively, for the nine and twelve months ended September 30, 2009 and 2008.

The following table summarizes TCEH’s secured debt to adjusted EBITDA ratio under the maintenance covenant in the TCEH Senior Secured Facilities and various other financial ratios of EFH Corp. and TCEH that are applicable under certain other covenants in the TCEH Senior Secured Facilities and the indentures governing the TCEH Senior Notes and the EFH Corp. Senior Notes as of September 30, 2009 and December 31, 2008 and the corresponding maintenance and other covenant threshold levels as of September 30, 2009:


	September 30, 2009	December 31, 2008	Threshold Level
Maintenance Covenant:
TCEH Senior Secured Facilities:
Secured debt to adjusted EBITDA ratio	4.68 to 1.00	4.77 to 1.00	Must not exceed 7.25 to 1.00

Debt Incurrence Covenants:
EFH Corp. Senior Notes:
EFH Corp. fixed charge coverage ratio	1.6 to 1.0	1.5 to 1.0	At least 2.0 to 1.0
TCEH fixed charge coverage ratio	1.4 to 1.0	1.3 to 1.0	At least 2.0 to 1.0
TCEH Senior Notes:
TCEH fixed charge coverage ratio	1.4 to 1.0	1.3 to 1.0	At least 2.0 to 1.0
TCEH Senior Secured Facilities:
TCEH fixed charge coverage ratio	1.4 to 1.0	1.3 to 1.0	At least 2.0 to 1.0

Restricted Payments/Limitations on Investments Covenants:
EFH Corp. Senior Notes:
General restrictions (non-Sponsor Group payments):
EFH Corp. fixed charge coverage ratio (a)	1.4 to 1.0	1.3 to 1.0	At least 2.0 to 1.0
General restrictions (Sponsor Group payments):
EFH Corp. fixed charge coverage ratio (a)	1.6 to 1.0	1.5 to 1.0	At least 2.0 to 1.0
EFH Corp. leverage ratio	7.0 to 1.0	6.9 to 1.0	Equal to or less than 7.0 to 1.0
TCEH Senior Notes:
TCEH fixed charge coverage ratio	1.4 to 1.0	1.3 to 1.0	At least 2.0 to 1.0
TCEH Senior Secured Facilities:
Payments to Sponsor Group:
TCEH total debt to adjusted EBITDA ratio	8.4 to 1.0	8.7 to 1.0	At least 6.5 to 1.0

(a)	The EFH Corp. fixed charge coverage ratio for non-Sponsor Group payments includes the results of Oncor Holdings and its subsidiaries. The EFH Corp. fixed charge coverage ratio for Sponsor Group payments excludes the results of Oncor Holdings and its subsidiaries.

Credit Ratings — The issuer credit ratings as of October 5, 2009 for EFH Corp. and its subsidiaries, except for Oncor, are CC, Caa1 and B by S&P, Moody’s and Fitch, respectively. The issuer credit ratings for Oncor are BBB+ and BBB- by S&P and Fitch, respectively.

Additionally, the rating agencies assign credit ratings on certain of our debt securities. The credit ratings assigned for these debt securities as of October 5, 2009 are presented below:


	S&P	Moody’s	Fitch
EFH Corp. (Senior Unsecured) (a)	CC	Caa3	B+
EFH Corp. (Unsecured) (b)	CC	Ca	CCC
EFC Holdings (Senior Unsecured)	CCC	Caa3	CCC
TCEH (Senior Secured)	B+	B2	BB
TCEH (Senior Unsecured) (c)	CC	Caa2	B
TCEH (Unsecured)	CCC	Caa3	CCC
Oncor (Senior Secured) (d)	BBB+	Baa1	BBB
Oncor (Senior Unsecured) (d)	BBB+	Baa1	BBB-

(a)

EFH Corp. Cash-Pay Notes and EFH Corp. Toggle Notes

(b)

Moody’s ratings of the EFH Corp. Series P, Series Q and Series R are Caa3, Ca and Ca, respectively.

(c)

TCEH Cash-Pay Notes and TCEH Toggle Notes. S&Ps ratings of the TCEH Cash-Pay Notes and the TCEH Toggle Notes are CC and CCC, respectively.

(d)

All of Oncor’s long-term debt is secured by a first priority lien and is considered senior secured debt.

In October 2009, both S&P and Moody’s announced rating actions related to their view that the debt exchange transaction announced by EFH Corp. in October 2009 represented a “distressed exchange.” As a result, S&P downgraded the corporate issuer ratings of EFH Corp., EFC Holdings and TCEH by four notches to CC from B- and affirmed their negative outlook. S&P also completed multi-notch downgrades of its ratings on issuances subject to the exchange to CC. S&P’s ratings outlook for Oncor remains stable. Moody’s affirmed its Caa1 corporate family ratings and negative outlook for EFH Corp. and TCEH but downgraded its probability of default rating for EFH Corp. and TCEH three notches to Ca from Caa1. Additionally, Moody’s downgraded its ratings on certain issuances subject to the exchange and placed the ratings of TCEH Cash-Pay Notes on review for possible downgrade. S&P and Moody’s have indicated that shortly after settlement of the debt exchange transaction they expect to replace these temporary “distressed exchange” ratings with new ratings based on their analysis of the outcome of the exchange. S&P and Moody’s ratings and outlooks for Oncor were unaffected by the “distressed exchange” downgrades. Fitch affirmed their ratings and outlook for EFH Corp., EFC Holdings and TCEH. All three agencies affirmed their ratings and outlook for Oncor.

In June 2009, Moody’s upgraded the long-term debt rating for Oncor’s senior secured debt by two notches from Baa3 to Baa1 citing, among other things, Oncor’s position as a rate-regulated electric transmission and distribution utility in Texas, reasonably supportive regulatory jurisdiction, solid financial credit metrics, adequate sources of near-term liquidity and the continued evidence of strong corporate independence from EFH Corp. Moody’s ratings outlook for Oncor remains stable.

In March 2009, Fitch downgraded certain ratings for EFH Corp., EFC Holdings and TCEH and changed the outlook for EFH Corp., EFC Holdings and TCEH from stable to negative, citing the effect of the economic slowdown in Texas and lower than anticipated market heat rates in ERCOT. Fitch’s ratings outlook for Oncor remains stable.

A rating reflects only the view of a rating agency, and is not a recommendation to buy, sell or hold securities. Ratings can be revised upward or downward at any time by a rating agency if such rating agency decides that circumstances warrant such a change.

Material Credit Rating Covenants and Credit Worthiness Effects on Liquidity — As a result of TCEH’s non-investment grade credit rating and considering collateral thresholds of certain retail and wholesale commodity contracts, as of September 30, 2009, counterparties to those contracts could have required TCEH to post up to an aggregate of $44 million in additional collateral. This amount largely represents the below market terms of these contracts as of September 30, 2009; thus, this amount will vary depending on the value of these contracts on any given day.

Certain transmission and distribution utilities in Texas have tariffs in place to assure adequate credit worthiness of any REP to support the REP’s obligation to collect securitization bond-related (transition) charges on behalf of the utility. Under these tariffs, as a result of TCEH’s below investment grade credit rating, TCEH is required to post collateral support in an amount equal to estimated transition charges over specified time periods. The amount of collateral support required to be posted, as well as the time period of transition charges covered, varies by utility. As of September 30, 2009, TCEH has posted collateral support in the form of letters of credit to the applicable utilities in an aggregate amount equal to $28 million, with $16 million of this amount posted for the benefit of Oncor.

The PUCT has rules in place to assure adequate credit worthiness of each REP, including the ability to return customer deposits, if necessary. Under these rules, as of September 30, 2009, TCEH maintained availability under its credit facilities of approximately $237 million. See “Regulation and Rates – Certification of REPs.”

The RRC has rules in place to assure adequate credit worthiness of parties that have mining reclamation obligations. Under these rules, should the RRC determine that the credit worthiness of Luminant Generation Company LLC (a subsidiary of TCEH) is not sufficient to support its reclamation obligations, TCEH may be required to post cash or letter of credit collateral support in an amount currently estimated to be approximately $600 million to $800 million. The actual amount (if required) could vary depending upon numerous factors, including Luminant Generation Company LLC’s credit worthiness and the level of mining reclamation obligations.

ERCOT also has rules in place to assure adequate credit worthiness of parties that schedule power on the ERCOT System. Under these rules, TCEH has posted collateral support, predominantly in the form of letters of credit, totaling $38 million as of September 30, 2009 (which is subject to weekly adjustments based on settlement activity with ERCOT).

Oncor and Texas Holdings agreed to the terms of a stipulation with major interested parties to resolve all outstanding issues in the PUCT review related to the Merger. As part of this stipulation, TCEH is required to post a letter of credit in an amount equal to $170 million to secure its payment obligations to Oncor if two or more of Oncor’s credit ratings are below investment grade.

Other arrangements of EFH Corp. and its subsidiaries, including Oncor’s credit facility, the accounts receivable securitization program (see Note 3 to Financial Statements) and certain leases, contain terms pursuant to which the interest rates charged under the agreements may be adjusted depending on the relevant credit ratings.

In the event that any or all of the additional collateral requirements discussed above are triggered, we believe we will have adequate liquidity to satisfy such requirements.

Material Cross Default Provisions — Certain financing arrangements contain provisions that may result in an event of default if there were a failure under other financing arrangements to meet payment terms or to observe other covenants that could or does result in an acceleration of payments due. Such provisions are referred to as “cross default” provisions.

A default by TCEH or any restricted subsidiary in respect of indebtedness, excluding indebtedness relating to the sale of receivables program, in an aggregate amount in excess of $200 million may result in a cross default under the TCEH Senior Secured Facilities. Under these facilities such a default may cause the maturity of outstanding balances ($22.356 billion at September 30, 2009) under such facilities to be accelerated.

The indenture governing the TCEH Senior Notes contains a cross acceleration provision where a payment default at maturity or on acceleration of principal indebtedness under any instrument or instruments of TCEH and any of its restricted subsidiaries in the aggregate amount equal to or greater than $250 million may cause the acceleration of the TCEH Senior Notes.

Under the terms of a TCEH rail car lease, which had approximately $48 million in remaining lease payments as of September 30, 2009 and terminates in 2017, if TCEH failed to perform under agreements causing its indebtedness in aggregate principal amount of $100 million or more to become accelerated, the lessor could, among other remedies, terminate the lease and effectively accelerate the payment of any remaining lease payments due under the lease.

Under the terms of a TCEH rail car lease, which had approximately $54 million in remaining lease payments as of September 30, 2009 and terminates in 2028, if obligations of TCEH in excess of $200 million in the aggregate for payments of obligations to third party creditors under lease agreements, deferred purchase agreements or loan or credit agreements have been accelerated prior to their original stated maturity, the lessor could, among other remedies, terminate the lease and effectively accelerate the payment of any remaining lease payments due under the lease.

The indenture governing the EFH Corp. Senior Notes contains a cross acceleration provision whereby a payment default at maturity or on acceleration of principal indebtedness under any instrument or instruments of EFH Corp. or any of its restricted subsidiaries in the aggregate amount equal to or greater than $250 million may cause the acceleration of the EFH Corp. Senior Notes.

The accounts receivable securitization program contains a cross default provision with a threshold of $200 million that applies in the aggregate to the originator, any parent guarantor of an originator or any subsidiary acting as collection agent under the program. TXU Receivables Company and EFH Corporate Services Company (a direct subsidiary of EFH Corp.), as collection agent, in the aggregate have a cross default threshold of $50,000. If any of the aforementioned defaults on indebtedness of the applicable threshold were to occur, the program could terminate.

We enter into energy-related and financial contracts, the master forms of which contain provisions whereby an event of default or acceleration of settlement would occur if we were to default under an obligation in respect of borrowings in excess of thresholds, which vary, stated in the contracts. The subsidiaries whose default would trigger cross default vary depending on the contract.

Each of TCEH’s natural gas hedging agreements that are secured with a lien on its assets on a pari passu basis with the TCEH Senior Secured Facilities contains a cross default provision. In the event of a default by TCEH or any of its subsidiaries relating to indebtedness (such amounts varying by contract but ranging from $200 million to $250 million) that results in the acceleration of such debt, then each counterparty under these hedging agreements would have the right to terminate its hedge agreement with TCEH and require all outstanding obligations under such agreement to be settled.

In the event of a default by TCEH relating to indebtedness in an amount equal to or greater than $200 million that results in the acceleration of such debt, then each counterparty under TCEH’s interest rate swap agreements with an aggregate derivative liability of $1.39 billion at September 30, 2009 would have the right to terminate its interest rate swap agreement with TCEH and require all outstanding obligations under such agreement to be settled.

A default by Oncor or any subsidiary thereof in respect of indebtedness in a principal amount in excess of $50 million may result in a cross default under its credit facility. Under this facility such a default may cause the maturity of outstanding balances ($537 million at September 30, 2009) under such facility to be accelerated.

Other arrangements, including leases, have cross default provisions, the triggering of which would not be expected to result in a significant effect on liquidity.

Guarantees — See Note 5 to Financial Statements for details of guarantees.

OFF–BALANCE SHEET ARRANGEMENTS

See discussion above under “Sale of Accounts Receivable” and in Note 3 to Financial Statements.

Also see Note 5 to Financial Statements regarding guarantees.

COMMITMENTS AND CONTINGENCIES

See Note 5 to Financial Statements for discussion of commitments and contingencies.

CHANGES IN ACCOUNTING STANDARDS

See Note 1 to Financial Statements for a discussion of changes in accounting standards.

REGULATION AND RATES

Regulatory Investigations and Reviews

See Note 5 to Financial Statements.

Certification of REPs

In April 2009, the PUCT finalized a rule relating to the Certification of Retail Electric Providers. The rule strengthens the certification requirements for REPs in order to better protect customers, transmission and distribution utilities (TDUs), and other REPs from the potential insolvency of REPs. The rule is considered a competition rule and thus is subject to judicial review as specified in PURA. The rule, among other things, increases creditworthiness and financial reporting requirements for REPs and provides additional customer protection requirements and regulatory asset consideration for TDU bad debt expenses. Under the rule, Oncor uncollectible amounts owed by REPs are deferred as a regulatory asset. Recovery of the regulatory asset will be considered in a future rate case. Accordingly, Oncor recognized an approximately $3 million one-time reversal of bad debt expense in the three months ended June 30, 2009 (reported in other income). Due to the commitments made to the PUCT in connection with the Merger, Oncor may not recover bad debt expense, or certain other costs and expenses, from rate payers in the event of a TXU Energy default or bankruptcy. Under the rule, REPs are required to amend their certifications, including the manner in which they meet financial requirements, by May 21, 2010. TXU Energy plans to file its amended certification no later than the first quarter 2010. Under the new financial requirements, which will be effective upon approval of the amended certification, as of September 30, 2009, the amount of additional available liquidity required to be maintained by TCEH would have been reduced from $237 million to approximately $93 million as a result of no longer having to reserve liquidity for payments related to TDUs.

Wholesale Market Design

In August 2003, the PUCT adopted a rule that, when implemented, will alter the wholesale market design in the ERCOT market. The rule requires ERCOT to:

•

use a stakeholder process to develop a new wholesale market model;

•

operate a voluntary day-ahead energy market;

•

directly assign all congestion rents to the resources that caused the congestion;

•

use nodal energy prices for resources;

•

provide information for energy trading hubs by aggregating nodes;

•

use zonal prices for loads, and

•

provide congestion revenue rights (but not physical rights).

ERCOT currently has a zonal wholesale market structure consisting of four geographic zones. The proposed location-based congestion-management market is referred to as a “nodal” market because wholesale pricing would differ across the various nodes on the transmission grid. The implementation of a nodal market is being done in conjunction with transmission improvements designed to reduce current congestion. Pursuant to a request from the PUCT, ERCOT announced in November 2008 a preliminary schedule for the implementation of the nodal market by December 2010.

ERCOT imposes a surcharge on all Qualified Scheduling Entities in the ERCOT market (including subsidiaries of TCEH) for the purpose of financing 38% of ERCOT’s expected nodal implementation costs. In November 2008, ERCOT filed a request with the PUCT for approval of an interim increase in the nodal surcharge from $0.169 per MWh to $0.375 per MWh. In September 2009, the PUCT approved an increase in the nodal surcharge to $0.375 per MWh, effective January 1, 2010. At the approved $0.375 per MWh nodal surcharge, the annual surcharge will be an estimated $30 million to $35 million, which is reported in fuel, purchased power costs and delivery fees. The implementation of a nodal market is still scheduled for December 2010. We cannot predict the ultimate impact of the proposed nodal wholesale market design on our operations or financial results.

Oncor Matters with the PUCT

Rate Case — In June 2008, Oncor filed for a rate review with the PUCT and 204 cities. On August 31, 2009, the PUCT issued a final order with respect to the rate review. The final order approves a total annual revenue requirement for Oncor of $2.64 billion, based on Oncor’s 2007 test year cost of service and customer characteristics. New rates were calculated for all customer classes using 2007 test year billing metrics and the approved class cost allocation and rate design. The PUCT staff has estimated that the final order results in an approximate $115 million increase in base rate revenues over Oncor’s 2007 adjusted test year revenues, before recovery of rate case expenses. Prior to implementing the new rates in September 2009, Oncor had already begun recovering $45 million of the $115 million increase as a result of approved transmission cost recovery factor and energy efficiency cost recovery factor filings, such as those discussed immediately below. Excluding the one-time write-off of certain regulatory assets discussed below, the result of the rate case is not expected to have a material effect on Oncor’s net income. Also see Note 13 to Financial Statements regarding the PUCT’s review of regulatory assets and liabilities.

Key findings made by the PUCT in the rate review include:

•

recognizing and affirming Oncor’s corporate ring-fence from EFH Corp. and its unregulated affiliates by rejecting a proposed consolidated tax savings adjustment arising out of EFH Corp.’s ability to offset Oncor’s taxable income against losses from other investments;

•

approving the recovery of all of Oncor’s capital investment in its transmission and distribution system, including investment in certain automated meters that will be replaced pursuant to Oncor’s advanced meter deployment plan;

•

denying recovery of $25 million of regulatory assets, which resulted in a $16 million after tax loss being recognized in the three months ended September 30, 2009, and

•

setting Oncor’s return on equity at 10.25%.

New rates were implemented upon approval of new tariffs in September 2009. The final order is subject to any motions for rehearing and appeals.

Transmission Rates — In order to recover increases in its transmission costs, including fees paid to other transmission service providers, Oncor is allowed to request an update twice a year to the transmission cost recovery factor (TCRF) component of its retail delivery rate charged to REPs. In January 2009, an application was filed to increase the TCRF, which was administratively approved in February 2009 and became effective in March 2009. This increase is expected to increase annualized revenues by $16 million. In July 2009, an application was filed to increase the TCRF, which was administratively approved in August 2009 and became effective September 1, 2009. This increase is expected to increase annualized revenues by approximately $14 million.

In September 2009, Oncor filed an application for an interim update of its wholesale transmission rate. Accordingly, annualized revenues are expected to increase by approximately $34 million. Approximately $21 million of this increase is recoverable through transmission rates charged to wholesale customers, and the remaining $13 million is recoverable from REPs through the TCRF component of Oncor’s delivery rates.

Application for 2010 Energy Efficiency Cost Recovery Factor — In May 2009, Oncor filed an application with the PUCT to request approval of an Energy Efficiency Cost Recovery Factor (EECRF) for 2010. PUCT rules require Oncor to make an annual EECRF filing by May 1 for implementation at the beginning of the next calendar year. The requested 2010 EECRF is $54 million, the same amount established for 2009, and would result in the same $0.92 per month charge for residential customers as proposed in Oncor’s rate case. As allowed by the rule, the 2010 EECRF is designed to recover the costs of the 2010 programs, the under-recovery of 2008 program costs, and a performance bonus based on 2008 results. Approval of the application as filed would result in an immediate recognition of $9 million in revenues, representing the performance bonus. In October 2009, the Administrative Law Judge assigned to the case issued a proposal for decision recommending that Oncor’s requests be granted as filed in its application. The PUCT is scheduled to rule on the proposal for decision at its November 5, 2009 open meeting and is not obligated to accept all or any part of the proposal for decision in its ruling.

Competitive Renewable Energy Zones (CREZs) — In January 2009, the PUCT assigned approximately $1.3 billion of CREZ construction projects to Oncor. A written order reflecting the PUCT’s decision was entered in March 2009, and an order on rehearing was issued by the PUCT in May 2009. The cost estimates for the CREZ construction projects are based upon cost analyses prepared by ERCOT. For the nine months ended September 30, 2009, CREZ-related capital expenditures totaled $84 million. It is expected that the necessary permitting actions and other requirements and all construction activities for the assigned construction projects will be completed by the end of 2013.

In October 2009, the PUCT initiated a proceeding to determine whether there is sufficient financial commitment from generators of renewable energy to grant Certificates of Convenience and Necessity (CCNs) for transmission facilities located in two areas in the panhandle of Texas designated as CREZs. If the PUCT determines that there is not sufficient financial commitment from the generators for either CREZ, the PUCT may take action, including delaying the filing of CREZ CCN applications until such time as the PUCT finds sufficient financial commitment for that CREZ in accordance with the financial commitment provisions of the PUCT’s rules. Three of the CREZ transmission projects awarded to Oncor are located in the two CREZs that are the subject of the proceeding. The estimated cost of these three transmission projects is approximately $380 million. Oncor expects the PUCT to issue an order concluding this proceeding in the second quarter of 2010.

Summary

We cannot predict future regulatory or legislative actions or any changes in economic and securities market conditions. Such actions or changes could significantly alter our basic financial position, results of operations or cash flows.

Item 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market risk is the risk that we may experience a loss in value as a result of changes in market conditions affecting factors such as commodity prices and interest rates, that may be experienced in the ordinary course of business. Our exposure to market risk is affected by a number of factors, including the size, duration and composition of our energy and financial portfolio, as well as the volatility and liquidity of markets. Instruments used to manage this exposure include interest rate swaps to manage interest rate risk related to indebtedness, as well as exchange traded, over-the-counter contracts and other contractual arrangements to manage commodity price risk as part of wholesale activities.

Risk Oversight

TCEH manages the commodity price, counterparty credit and commodity-related operational risk related to the unregulated energy business within limitations established by senior management and in accordance with overall risk management policies. Interest rate risk is managed centrally by the corporate treasury function. Market risks are monitored by risk management groups that operate independently of the wholesale commercial operations, utilizing defined practices and analytical methodologies. These techniques measure the risk of change in value of the portfolio of contracts and the hypothetical effect on this value from changes in market conditions and include, but are not limited to, Value at Risk (VaR) methodologies. Key risk control activities include, but are not limited to, transaction review and approval (including credit review), operational and market risk measurement, validation of transaction capture, portfolio valuation and reporting, including mark-to-market valuation, VaR and other risk measurement metrics.

We have a corporate risk management organization that is headed by the Chief Financial Officer, who also functions as the Chief Risk Officer. The Chief Risk Officer, through his designees, enforces applicable risk limits, including the respective policies and procedures to ensure compliance with such limits and evaluates the risks inherent in our businesses and their associated transactions.

Commodity Price Risk

TCEH is subject to the inherent risks of market fluctuations in the price of electricity, natural gas and other energy-related products it markets or purchases. The company actively manages its portfolio of owned generation assets, fuel supply and retail sales load to mitigate the near-term impacts of these risks on results of operations. The company, similar to other participants in the market, cannot fully manage the long-term value impact of structural declines or increases in natural gas and power prices and spark spreads (differences between the market price of electricity and its cost of production).

In managing energy price risk, TCEH enters into a variety of market transactions including, but not limited to, short- and long-term contracts for physical delivery, exchange traded and over-the-counter financial contracts and bilateral contracts with customers. Activities include hedging, the structuring of long-term contractual arrangements and proprietary trading. The company continuously monitors the valuation of identified risks and adjusts positions based on current market conditions. The company strives to use consistent assumptions regarding forward market price curves in evaluating and recording the effects of commodity price risk.

Long-Term Hedging Program — See “Significant Activities and Events” above for a description of the program, including potential effects on reported results.

VaR Methodology — A VaR methodology is used to measure the amount of market risk that exists within the portfolio under a variety of market conditions. The resultant VaR produces an estimate of a portfolio’s potential for loss given a specified confidence level and considers among other things, market movements utilizing standard statistical techniques given historical and projected market prices and volatilities.

A Monte Carlo simulation methodology is used to calculate VaR and is considered by management to be the most effective way to estimate changes in a portfolio’s value based on assumed market conditions for liquid markets. The use of this method requires a number of key assumptions, such as use of (i) an assumed confidence level; (ii) an assumed holding period (i.e. the time necessary for management action, such as to liquidate positions); and (iii) historical estimates of volatility and correlation data.

Trading VaR — This measurement estimates the potential loss in fair value, due to changes in market conditions, of all contracts entered into for trading purposes based on a 95% confidence level and an assumed holding period of five to 60 days.


	Nine Months Ended September 30, 2009		Year Ended December 31, 2008
Month-end average Trading VaR:	$	4	$	6

Month-end high Trading VaR:	$	7	$	15

Month-end low Trading VaR:	$	2	$	2

VaR for Energy-Related Contracts Subject to Mark-to-Market (MtM) Accounting — This measurement estimates the potential loss in fair value, due to changes in market conditions, of all contracts marked-to-market in net income (principally hedges not accounted for as cash flow hedges and trading positions), based on a 95% confidence level and an assumed holding period of five to 60 days.


	Nine Months Ended September 30, 2009		Year Ended December 31, 2008
Month-end average MtM VaR:	$	1,034	$	2,290

Month-end high MtM VaR:	$	1,470	$	3,549

Month-end low MtM VaR:	$	638	$	1,087

Earnings at Risk (EaR) — This measurement estimates the potential reduction of pretax earnings for the periods presented, due to changes in market conditions, of all energy-related contracts marked-to-market in net income and contracts not marked-to-market in net income that are expected to be settled within the fiscal year (physical purchases and sales of commodities). Transactions accounted for as cash flow hedges are also included for this measurement. A 95% confidence level and a five to 60 day holding period are assumed in determining EaR.


	Nine Months Ended September 30, 2009		Year Ended December 31, 2008
Month-end average EaR:	$	1,034	$	2,300

Month-end high EaR:	$	1,450	$	3,916

Month-end low EaR:	$	676	$	1,069

The decreases in the risk measures (MtM VaR and EaR) above were primarily driven by lower natural gas prices in 2009.

Interest Rate Risk

As of September 30, 2009, the potential reduction of annual pretax earnings due to a one percentage point (100 basis points) increase in floating interest rates on long-term debt totaled approximately $31 million, taking into account the interest rate swaps discussed in Note 4 to Financial Statements.

Credit Risk

Credit Risk — Credit risk relates to the risk of loss associated with nonperformance by counterparties. We maintain credit risk policies with regard to our counterparties to minimize overall credit risk. These policies prescribe practices for evaluating a potential counterparty’s financial condition, credit rating and other quantitative and qualitative credit criteria and specify authorized risk mitigation tools including, but not limited to, use of standardized master netting contracts and agreements that allow for netting of positive and negative exposures associated with a single counterparty. We have processes for monitoring and managing credit exposure of our businesses including methodologies to analyze counterparties’ financial strength, measurement of current and potential future exposures and contract language that provides rights for netting and set-off. Credit enhancements such as parental guarantees, letters of credit, surety bonds and margin deposits are also utilized. Additionally, individual counterparties and credit portfolios are managed to assess overall credit exposure. This evaluation results in establishing exposure limits or collateral requirements for entering into an agreement with a counterparty that creates exposure. Additionally, we have established controls to determine and monitor the appropriateness of these limits on an ongoing basis. Prospective material adverse changes in the payment history or financial condition of a counterparty or downgrade of its credit quality result in the reassessment of the credit limit with that counterparty. This process can result in the subsequent reduction of the credit limit or a request for additional financial assurances.

Credit Exposure — Our gross exposure to credit risk associated with trade accounts receivable (retail and wholesale) and net asset positions arising from hedging and trading activities totaled $2.104 billion at September 30, 2009. The components of this exposure are discussed in more detail below.

Assets subject to credit risk as of September 30, 2009 include $1.074 billion in accounts receivable from the retail sale of electricity to residential and business customers. Cash deposits held as collateral for these receivables totaled $93 million at September 30, 2009. The risk of material loss (after consideration of bad debt allowances) from nonperformance by these customers is unlikely based upon historical experience. Allowances for uncollectible accounts receivable are established for the potential loss from nonpayment by these customers based on historical experience, market or operational conditions and changes in the financial condition of large business customers.

Assets subject to credit risk also include accounts receivable from electricity transmission and distribution services. This exposure, which totaled $255 million at September 30, 2009, consists almost entirely of noninvestment grade trade accounts receivable. Of this amount, $191 million represents trade accounts receivable from REPs. Oncor has a customer with subsidiaries that collectively represent 14% of the total exposure. No other nonaffiliated parties represent 10% or more of the total exposure.

The remaining credit exposure arises from wholesale energy sales and hedging and trading activities. Counterparties to these transactions include energy companies, financial institutions, electric utilities, independent power producers, oil and gas producers, local distribution companies and energy trading and marketing companies. As of September 30, 2009, the exposure to credit risk from these counterparties totaled $775 million taking into account the standardized master netting contracts and agreements described above but before taking into account $128 million in credit collateral (cash, letters of credit and other credit support). The net exposure (after credit collateral) of $647 million decreased approximately $148 million in the nine months ended September 30, 2009, reflecting the netting and right of setoff related to certain interest rate and commodity hedging transactions under a new derivative agreement with a counterparty (see Note 7 to Financial Statements).

Of this $647 million net exposure, 97% is with investment grade customers and counterparties, as determined using publicly available information including major rating agencies’ published ratings and our internal credit evaluation process. Those customers and counterparties without a S&P rating of at least BBB- or similar rating from another major rating agency are rated using internal credit methodologies and credit scoring models to estimate a S&P equivalent rating. The company routinely monitors and manages credit exposure to these customers and counterparties on this basis.

The following table presents the distribution of credit exposure as of September 30, 2009 arising from wholesale energy sales and hedging and trading activities. This credit exposure represents wholesale trade accounts receivable and net asset positions on the balance sheet arising from hedging and trading activities after taking into consideration netting and setoff provisions within each contract and any master netting contracts with counterparties. The amounts below do not include asset liens held as security for a portion of the net exposure.


									Net Exposure by Maturity
	Exposure Before Credit Collateral			Credit Collateral		Net Exposure			2 years or less		Between 2-5 years		Greater than 5 years			Total
Investment grade	$	754		$	127	$	627		$	724	$	29	$	(126	)	$	627
Noninvestment grade		21			1		20			20		—		—			20

Totals	$	775		$	128	$	647		$	744	$	29	$	(126	)	$	647


Investment grade		97	%				97	%
Noninvestment grade		3	%				3	%

In addition to the exposures in the table above, contracts classified as “normal” purchase or sale and non-derivative contractual commitments are not marked-to-market in the financial statements. Such contractual commitments may contain pricing that is favorable considering current market conditions and therefore represent economic risk if the counterparties do not perform. Nonperformance could have a material adverse impact on future results of operations, financial condition and cash flows.

We do not anticipate any material adverse effect on our financial position or results of operations due to nonperformance by any wholesale customer or counterparty.

Significant (10% or greater) concentration of credit exposure exists with two counterparties, which represented 55% and 10% of the net $647 million exposure. Exposure to these counterparties is viewed to be within an acceptable level of risk tolerance due to the applicable counterparty’s credit rating and the importance of our business relationship with the counterparty. However, this concentration increases the risk that a default would have a material effect on results of operations.

With respect to credit risk related to the long-term hedging program, over 99% of the transaction volumes are with counterparties with an A credit rating or better. However, there is current and potential credit concentration risk related to the limited number of counterparties that comprise the substantial majority of the program with such counterparties being in the banking and financial sector. The transactions with these counterparties contain certain credit rating provisions that would require the counterparties to post collateral in the event of a material downgrade in the credit rating of the counterparties. An event of default by one or more hedge counterparties could subsequently result in termination-related settlement payments that reduce available liquidity if amounts are owed to the counterparties related to the commodity contracts or delays in receipts of expected settlements if the hedge counterparties owe amounts to us. While the potential concentration of risk with these counterparties is viewed to be within an acceptable risk tolerance, the exposure to hedge counterparties is managed through various ongoing risk management measures.

FORWARD-LOOKING STATEMENTS

This report and other presentations made by us contain “forward-looking statements.” All statements, other than statements of historical facts, that are included in this report, or made in presentations, in response to questions or otherwise, that address activities, events or developments that we expect or anticipate to occur in the future, including such matters as projections, capital allocation, future capital expenditures, business strategy, competitive strengths, goals, future acquisitions or dispositions, development or operation of power generation assets, market and industry developments and the growth of our business and operations (often, but not always, through the use of words or phrases such as “will likely result,” “are expected to,” “will continue,” “is anticipated,” “estimated,” “projection,” “target,” “goal,” “objective” and “outlook”), are forward-looking statements. Although we believe that in making any such forward-looking statement our expectations are based on reasonable assumptions, any such forward-looking statement involves uncertainties and is qualified in its entirety by reference to the discussion of risk factors under “Risk Factors” in the 2008 Form 10-K and the following important factors, among others, that could cause our actual results to differ materially from those projected in such forward-looking statements:

•

prevailing governmental policies and regulatory actions, including those of the Texas Legislature, the Governor of Texas, the US Congress, FERC, the PUCT, the RRC, the NRC, the EPA and the TCEQ, with respect to, among other things:

•

allowed prices;

•

allowed rates of return;

•

permitted capital structure;

•

industry, market and rate structure;

•

purchased power and recovery of investments;

•

operations of nuclear generating facilities;

•

operations of mines;

•

acquisitions and disposal of assets and facilities;

•

development, construction and operation of facilities;

•

decommissioning costs;

•

present or prospective wholesale and retail competition;

•

changes in tax laws and policies, and

•

changes in and compliance with environmental and safety laws and policies, including climate change initiatives;

•

legal and administrative proceedings and settlements;

•

general industry trends;

•

economic conditions, including the current recessionary environment;

•

our ability to attract and retain profitable customers;

•

our ability to profitably serve our customers;

•

restrictions on competitive retail pricing;

•

changes in wholesale electricity prices or energy commodity prices;

•

changes in prices of transportation of natural gas, coal, crude oil and refined products;

•

unanticipated changes in market heat rates in the ERCOT electricity market;

•

our ability to effectively hedge against changes in commodity prices, market heat rates and interest rates;

•

weather conditions and other natural phenomena, and acts of sabotage, wars or terrorist activities;

•

unanticipated population growth or decline, or changes in market demand and demographic patterns;

•

changes in business strategy, development plans or vendor relationships;

•

access to adequate transmission facilities to meet changing demands;

•

unanticipated changes in interest rates, commodity prices, rates of inflation or foreign exchange rates;

•

unanticipated changes in operating expenses, liquidity needs and capital expenditures;

•

commercial bank market and capital market conditions and the potential impact of continued disruptions in US credit markets;

•

access to capital, the cost of such capital, and the results of financing and refinancing efforts, including availability of funds in capital markets;

•

financial restrictions placed on us by our credit facilities and indentures governing our debt instruments;

•

our ability to generate sufficient cash flow to make interest payments on our debt instruments;

•

competition for new energy development and other business opportunities;

•

inability of various counterparties to meet their obligations with respect to our financial instruments;

•

changes in technology used by and services offered by us;

•

changes in electricity transmission that allow additional electricity generation to compete with our generation assets;

•

significant changes in our relationship with our employees, including the availability of qualified personnel, and the potential adverse effects if labor disputes or grievances were to occur;

•

changes in assumptions used to estimate costs of providing employee benefits, including pension and OPEB benefits, and future funding requirements related thereto;

•

changes in assumptions used to estimate future executive compensation payments;

•

hazards customary to the industry and the possibility that we may not have adequate insurance to cover losses resulting from such hazards;

•

significant changes in critical accounting policies;

•

actions by credit rating agencies;

•

our ability to effectively execute our operational strategy;

•

our ability to implement cost reduction initiatives, and

•

with respect to our lignite-fueled generation construction and development program, more specifically, our ability to fund such investments, changes in competitive market rules, adverse judicial rulings, changes in environmental laws or regulations, changes in electric generation and emissions control technologies, changes in projected demand for electricity, our ability and the ability of our contractors to attract and retain, at projected rates, skilled labor for constructing the new generating units, changes in wholesale electricity prices or energy commodity prices, transmission capacity and constraints, supplier performance risk, force majeure events, changes in the cost and availability of materials necessary for the construction program and our ability to manage the significant construction, commissioning and start-up program to a timely conclusion with limited cost overruns.

Any forward-looking statement speaks only as of the date on which it is made, and there is no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for us to predict all of them; nor can we assess the impact of each such factor or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.

INDUSTRY AND MARKET INFORMATION

The industry and market data and other statistical information used throughout this report are based on independent industry publications, government publications, reports by market research firms or other published independent sources, including certain data published by ERCOT or the PUCT. We did not commission any of these publications or reports. Some data is also based on good faith estimates, which are derived from our review of internal surveys, as well as the independent sources listed above. Independent industry publications and surveys generally state that they have obtained information from sources believed to be reliable, but do not guarantee the accuracy and completeness of such information. While we believe that each of these studies and publications is reliable, we have not independently verified such data and make no representation as to the accuracy of such information. Forecasts are particularly likely to be inaccurate, especially over long periods of time, and we do not know what assumptions regarding general economic growth are used in preparing the forecasts included in this report. Similarly, while we believe that such internal and external research is reliable, it has not been verified by any independent sources, and we make no assurances that the predictions contained therein are accurate.

Item 4.

CONTROLS AND PROCEDURES.

An evaluation was performed under the supervision and with the participation of our management, including the principal executive officer and principal financial officer, of the effectiveness of the design and operation of the disclosure controls and procedures in effect as of the end of the current period included in this report. Based on the evaluation performed, our management, including the principal executive officer and principal financial officer, concluded that the disclosure controls and procedures were effective. During the most recent fiscal quarter covered by this report, there has been no change in our internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting, except as discussed below.

During the second quarter of 2009, we implemented a new SAP retail customer management system, including billing and accounts receivable. As with any material change in our internal control over financial reporting, the design of this application, along with the design of the internal controls included in our processes, were evaluated for effectiveness.

PART II. OTHER INFORMATION

Item 1.

LEGAL PROCEEDINGS.

Reference is made to the discussion in Note 5 to Financial Statements regarding legal proceedings.

Item 1A.

RISK FACTORS.

There have been no material changes from the risk factors disclosed under the heading “Risk Factors” in Item 1A of the 2008 Form 10-K, except for the risk factor discussed below and the information discussed elsewhere in this Form 10-Q that provides factual updates to the risk factors contained in the 2008 Form 10-K.

Our use of assets as collateral for hedging arrangements could be materially impacted if certain proposed legislation regarding the regulation of over-the-counter financial derivatives were to be enacted and be applicable to us.

The Obama administration has proposed financial market reforms with respect to the currently unregulated Over-the-Counter (OTC) financial derivatives market. As a result, there are currently competing bills in the US House of Representatives that propose to regulate OTC derivatives. Certain of the proposals require entities to clear OTC derivatives that are currently traded on the bilateral market through exchanges, which require that all collateral be in the form of cash. We have entered into a significant number of asset-backed OTC derivatives to hedge risks associated with commodity and interest rate exposure. If this legislation were to be passed and be applicable to us so that we were required to clear our OTC derivatives through exchanges, we would likely be precluded from using our noncash assets as collateral for hedging arrangements. This preclusion could have a material impact on our liquidity, particularly if the final legislation does not provide for the grandfathering of existing OTC derivatives. As a result, if applied to our OTC derivatives transactions, this legislation could significantly increase our costs of entering into OTC derivatives and/or could significantly limit our ability to enter into OTC derivatives and hedge our commodity and interest rate risks. The most recent legislative developments in the US House of Representatives indicate a willingness to grandfather existing OTC derivatives and to exclude from the new clearing requirements swaps used for hedging purposes by end users. However, the proposed legislation is in the early stages of consideration, and we cannot predict whether or when the legislation will be enacted or whether these exemptions will be included in the final legislation.

Item 5.

OTHER INFORMATION.

On October 29, 2009, the Organization and Compensation Committee (O&C Committee) of the Board of Directors of EFH Corp. approved several changes in EFH Corp.’s compensation program for its owner-operators (i.e. employees that either own common stock of EFH Corp. or have options to purchase shares of EFH Corp.’s common stock). The O&C Committee did so to provide incentives for retention and performance, reflect the effects of the recent economic dislocation and maintain alignment with the sponsor group that controls EFH Corp. In particular, each owner-operator (other than (i) the named executive officers whose changes are described below and (ii) a small group of owner-operators whose changes will be similar to the named executive officers’ changes) will be offered the opportunity to exchange his/her existing unvested performance-based stock options granted under the 2007 Stock Incentive Plan for Key Employees of Energy Future Holdings Corp. and Affiliates (Stock Option Plan) with a strike price of $5.00 per share and a vesting schedule through October 2012 for new time-based stock options granted under the Stock Option Plan with a strike price of $3.50 per share (the current market valuation of each share), with one-half of these options cliff vesting in September 2012 and one-half of these options cliff vesting in September 2014.

The compensation changes for EFH Corp.’s named executive officers are described below. This disclosure should be read in conjunction with Item 11 “Executive Compensation” in the 2008 Form 10-K.

Base Salary

The O&C Committee approved an increase in the base salary for certain of its named executive officers as follows: Mr. David Campbell’s, Luminant’s Chief Executive Officer, base salary will increase to $700,000; Mr. Paul Keglevic’s, EFH Corp.’s Chief Financial Officer, base salary will increase to $650,000; Mr. Mac McFarland’s, Luminant’s Chief Commercial Officer, base salary will increase to $600,000; and Mr. Robert Walters’, EFH Corp.’s General Counsel, base salary will increase to $600,000. These increases were made after considering relevant market compensation data and will be effective January 1, 2010.

Executive Annual Incentive Plan

The O&C Committee approved an increase in the annual target award under the Energy Future Holdings Corp. Executive Annual Incentive Plan (AIP), which is computed as a percentage of base salary, from 75% to 85% for Messrs. Keglevic, Campbell, McFarland, Walters and James Burke, the Chief Executive Officer of TXU Energy. These increases will be effective for the 2010 AIP award period.

Long Term Incentive

The O&C Committee approved the adoption of a new retention incentive award to be included by amendment in the named executive officers’ employment agreements (Retention Award). Under the terms of the Retention Award, each of Messrs. Keglevic, Campbell, McFarland, Burke and Walters (collectively, the Executive Officers) will be entitled to receive on September 30, 2012, to the extent such Executive Officer remains employed by EFH Corp. on such date (with customary exceptions for death, disability and leaving for “good reason” or termination without “cause”), an additional one-time, lump-sum cash payment equal to 75% of the aggregate AIP award received by such executive officer for fiscal years 2009, 2010 and 2011.

Stock Options

The O&C Committee approved the grant of new stock options to each of the Executive Officers under the Stock Option Plan with a strike price of $3.50 per share (the fair market value of each share on the date of grant) as set forth in the table below. Certain of these stock options will vest 100% on September 30, 2014 (Cliff-Vested Options) and certain of these stock options will vest 20% per year over a five-year period beginning September 30, 2009 (Time-Vested Options). In connection with the grant of these new stock options, each Executive Officer will surrender to EFH Corp. a portion of their currently outstanding unvested performance-related stock options as set forth in the table below.


Executive Officer	Cliff-Vested Options	Time-Vested Options	Surrendered Options
David Campbell	800,000	800,000	800,000
Paul Keglevic	500,000	500,000	500,000
James Burke	490,000	200,000	490,000
Mac McFarland	400,000	400,000	400,000
Robert Walters	400,000	400,000	400,000

100

Item 6.

EXHIBITS

(a) Exhibits filed or furnished as part of Part II are:


Exhibits	Previously Filed With File Number	As Exhibit

(10)	Material Contracts.
	Credit Agreements

10(a)	1-12833 Form 8-K (filed August 10, 2009)	10.1	–	Amendment No. 1, dated as of August 7, 2009, to the $24,500,000,000 Credit Agreement dated as of October 10, 2007 among Energy Future Competitive Holdings Company, Texas Competitive Electric Holdings Company LLC, as the Borrower, Citibank, N.A., as Administrative Agent, Goldman Sachs Credit Partners L.P. as Posting Agent, J. Aron & Company, as Posting Calculation Agent and the several lenders thereto from time to time.

10(b)	1-12833 Form 8-K (filed August 10, 2009)	10.2	–	Amended and Restated Collateral Agency and Intercreditor Agreement, dated as of October 10, 2007, as amended and restated as of August 7, 2009, among Energy Future Competitive Holdings Company, Texas Competitive Electric Holdings Company LLC, the subsidiary guarantors party thereto, Citibank, N.A., as administrative agent and collateral agent, Credit Suisse Energy LLC, J. Aron & Company, Morgan Stanley Capital Group Inc., Citigroup Energy Inc., and each other secured commodity hedge counterparty from time to time party thereto, and any other person that becomes a secured party pursuant thereto.

10(c)	1-12833 Form 8-K (filed August 10, 2009)	10.3	–	Amended and Restated Security Agreement, dated as of October 10, 2007, as amended and restated as of August 7, 2009, among Energy Future Competitive Holdings Company, Texas Competitive Electric Holdings Company LLC, the subsidiary grantors party thereto, and Citibank, N.A., as collateral agent for the benefit of the secured parties under the $24,500,000,000 Credit Agreement.

10(d)	1-12833 Form 8-K (filed August 10, 2009)	10.4	–	Amended and Restated Pledge Agreement, dated as of October 10, 2007, as amended and restated as of August 7, 2009, among Energy Future Competitive Holdings Company, Texas Competitive Electric Holdings Company LLC, the subsidiary pledgors party thereto, and Citibank, N. A., as collateral agent for the benefit of the secured parties under the $24,500,000,000 Credit Agreement.

(31)	Rule 13a – 14(a)/15d – 14 (a) Certifications.

31(a)			–	Certification of John Young, principal executive officer of Energy Future Holdings Corp.

31(b)			–	Certification of Paul M. Keglevic, principal financial officer of Energy Future Holdings Corp.

101


(32)	Section 1350 Certifications.

32(a)		–	Certification of John Young, principal executive officer of Energy Future Holdings Corp.

32(b)		–	Certification of Paul M. Keglevic, principal financial officer of Energy Future Holdings Corp.

(99)	Additional Exhibits.

99(a)		–	Condensed Statement of Consolidated Income (Loss) – Twelve Months Ended September 30, 2009.

99(b)		–	Energy Future Holdings Corp. Consolidated Adjusted EBITDA reconciliation for the nine and twelve months ended September 30, 2009 and 2008.

99(c)		–	TCEH Consolidated Adjusted EBITDA reconciliation for the nine and twelve months ended September 30, 2009 and 2008.

102

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


Energy Future Holdings Corp.

By:		/s/ Stan Szlauderbach
Name:		Stan Szlauderbach
Title:		Senior Vice President and Controller
		(Principal Accounting Officer)

Date: October 29, 2009

103

Energy Future Holdings Corp /TX/ - FORM 10-Q - October 29, 2009

Attached files

Energy Future Holdings Corp /TX/ Reports

Also read